CONNECTICUT LIGHT & POWER CO - Quarter Report: 2010 March (Form 10-Q)

March 2010 Form 10-Q

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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549

FORM 10-Q


[X]	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

	For the Quarterly Period Ended March 31, 2010
	OR
[ ]	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

	For the transition period from ____________ to ____________


Commission File Number	Registrant; State of Incorporation; Address; and Telephone Number	I.R.S. Employer Identification No.

1-5324	NORTHEAST UTILITIES (a Massachusetts voluntary association) One Federal Street Building 111-4 Springfield, Massachusetts 01105 Telephone: (413) 785-5871	04-2147929

0-00404	THE CONNECTICUT LIGHT AND POWER COMPANY (a Connecticut corporation) 107 Selden Street Berlin, Connecticut 06037-1616 Telephone: (860) 665-5000	06-0303850

1-6392	PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE (a New Hampshire corporation) Energy Park 780 North Commercial Street Manchester, New Hampshire 03101-1134 Telephone: (603) 669-4000	02-0181050

0-7624	WESTERN MASSACHUSETTS ELECTRIC COMPANY (a Massachusetts corporation) One Federal Street Building 111-4 Springfield, Massachusetts 01105 Telephone: (413) 785-5871	04-1961130

______________________________________________________________________________

Indicate by check mark whether the registrants (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrants were required to file such reports), and (2) have been subject to such filing requirements for the past 90 days:


	Yes	No

	ü

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).


	Yes	No

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of "accelerated filer and large accelerated filer" in Rule 12b-2 of the Exchange Act. (check one):


	Large Accelerated Filer	Accelerated Filer	Non-accelerated Filer

Northeast Utilities	ü
The Connecticut Light and Power Company			ü
Public Service Company of New Hampshire			ü
Western Massachusetts Electric Company			ü

Indicate by check mark whether the registrants are shell companies (as defined in Rule 12b-2 of the Exchange Act):


	Yes	No

Northeast Utilities		ü
The Connecticut Light and Power Company		ü
Public Service Company of New Hampshire		ü
Western Massachusetts Electric Company		ü

Indicate the number of shares outstanding of each of the issuers' classes of common stock, as of the latest practicable date:


Company - Class of Stock	Outstanding as of April 30, 2010
Northeast Utilities Common shares, $5.00 par value	175,995,600 shares

The Connecticut Light and Power Company Common stock, $10.00 par value	6,035,205 shares

Public Service Company of New Hampshire Common stock, $1.00 par value	301 shares

Western Massachusetts Electric Company Common stock, $25.00 par value	434,653 shares

Northeast Utilities holds all of the 6,035,205 shares, 301 shares, and 434,653 shares of the outstanding common stock of The Connecticut Light and Power Company, Public Service Company of New Hampshire and Western Massachusetts Electric Company, respectively.

Public Service Company of New Hampshire and Western Massachusetts Electric Company each meet the conditions set forth in General Instructions H(1)(a) and (b) of Form 10-Q, and each is therefore filing this Form 10-Q with the reduced disclosure format specified in General Instruction H(2) of Form 10-Q.


GLOSSARY OF TERMS
The following is a glossary of frequently used abbreviations or acronyms that are found in this report.

CURRENT OR FORMER NU COMPANIES, SEGMENTS OR INVESTMENTS:

Boulos	E.S. Boulos Company
CL&P	The Connecticut Light and Power Company
HWP	HWP Company, formerly the Holyoke Water Power Company
NAESCO	North Atlantic Energy Service Corporation
NGS	Northeast Generation Services Company and subsidiaries
NPT	Northern Pass Transmission, LLC
NUTV	NU Transmission Ventures, Inc.
NU or the Company	Northeast Utilities and subsidiaries
NU Enterprises	NU Enterprises, Inc., the parent company of Select Energy, NGS, SECI and Boulos
NUSCO	Northeast Utilities Service Company
NU parent and other companies	NU parent and other companies is comprised of NU parent, NUSCO and other subsidiaries, including HWP, RRR (a real estate subsidiary), and the non-energy-related subsidiaries of Yankee (Yankee Energy Services Company, and Yankee Energy Financial Services Company)
PSNH	Public Service Company of New Hampshire
Regulated companies	NU's Regulated companies, comprised of the electric distribution and transmission segments of CL&P, PSNH and WMECO, the generation segment of PSNH, and Yankee Gas, a natural gas local distribution company
RRR	The Rocky River Realty Company
SECI	Select Energy Contracting, Inc.
Select Energy	Select Energy, Inc.
SESI	Select Energy Services, Inc., a former subsidiary of NU Enterprises
WMECO	Western Massachusetts Electric Company
Yankee	Yankee Energy System, Inc.
Yankee Gas	Yankee Gas Services Company

REGULATORS:

DOE	U.S. Department of Energy
DPU	Massachusetts Department of Public Utilities
DPUC	Connecticut Department of Public Utility Control
FERC	Federal Energy Regulatory Commission
NHPUC	New Hampshire Public Utilities Commission
SEC	Securities and Exchange Commission


OTHER:

2009 Form 10-K	The Northeast Utilities and subsidiaries combined 2009 Annual Report on Form 10-K as filed with the SEC
2010 Healthcare Act	Patient Protection and Affordable Care Act
AFUDC	Allowance For Funds Used During Construction
AMI	Advanced metering infrastructure
ARO	Asset Retirement Obligation
C&LM	Conservation and Load Management
CfD	Contract for Differences
CSC	Connecticut Siting Council
CTA	Competitive Transition Assessment
CWIP	Construction work in progress
EFSB	Energy Facilities Siting Board
EPS	Earnings Per Share
ES	Default Energy Service
ESOP	Employee Stock Ownership Plan
FASB	Financial Accounting Standards Board
Fitch	Fitch Ratings
FMCC	Federally Mandated Congestion Charge
FTR	Financial Transmission Rights
GAAP	Accounting principles generally accepted in the United States of America
GSC	Generation Service Charge


GSRP	Greater Springfield Reliability Project
GWh	Gigawatt Hours
HG&E	Holyoke Gas and Electric
HQ	Hydro-Québec, a corporation wholly-owned by the Québec government, including its divisions that produce, transmit and distribute electricity in Québec, Canada
HVDC	High voltage direct current
IPP	Independent Power Producers
ISO-NE	New England Independent System Operator or ISO New England, Inc.
KV	Kilovolt
KWh	Kilowatt-Hours
LBCB	Lehman Brothers Commercial Bank, Inc.
LNG	Liquefied natural gas
LOC	Letter of Credit
LRS	Last resort service
MA DEP	Massachusetts Department of Environmental Protection
MGP	Manufactured Gas Plant
MMBtu	One million British thermal units
Money Pool	Northeast Utilities Money Pool
Moody's	Moody's Investors Services, Inc.
MW	Megawatt
MWh	Megawatt-Hours
NEEWS	New England East-West Solutions
Northern Pass	A high voltage direct current transmission line project from Canada to New Hampshire
NU supplemental benefit trust	The NU Trust Under Supplemental Executive Retirement Plan
NYMEX	New York Mercantile Exchange
PBOP	Postretirement Benefits Other Than Pension
PBOP Plan	Postretirement Benefits Other Than Pension Plan that provides certain retiree health care benefits, primarily medical and dental, and life insurance benefits
PCRBs	Pollution Control Revenue Bonds
Pension Plan	Single uniform noncontributory defined benefit retirement plan
PGA	Purchased Gas Adjustment
PPA	Pension Protection Act
Regulatory ROE	The average cost of capital method for calculating the return on equity related to the distribution and generation business segments excluding the wholesale transmission segment
ROE	Return on Equity
RFP	Request for Proposal
RRB	Rate Reduction Bond
RSUs	Restricted share units
S&P	Standard & Poor's Financial Services LLC
SBC	Systems Benefits Charge
SCRC	Stranded Cost Recovery Charge
SERP	Supplemental Executive Retirement Plan
SS	Standard service
TCAM	Transmission Cost Adjustment Mechanism
TSA	Transmission Services Agreement
UI	The United Illuminating Company
VIE	Variable interest entity
Yankee Companies	Connecticut Yankee Atomic Power Company, Yankee Atomic Electric Company and Maine Yankee Atomic Power Company

NORTHEAST UTILITIES AND SUBSIDIARIES
THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES
WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY

TABLE OF CONTENTS


	Page

PART I - FINANCIAL INFORMATION

ITEM 1 – Unaudited Condensed Consolidated Financial Statements for the Following Companies:

Northeast Utilities and Subsidiaries

Condensed Consolidated Balance Sheets (Unaudited) - March 31, 2010 and December 31, 2009	2

Condensed Consolidated Statements of Income (Unaudited) - Three Months Ended March 31, 2010 and 2009	4

Condensed Consolidated Statements of Cash Flows (Unaudited) - Three Months Ended March 31, 2010 and 2009	5

The Connecticut Light and Power Company and Subsidiaries

Condensed Consolidated Balance Sheets (Unaudited) - March 31, 2010 and December 31, 2009	8

Condensed Consolidated Statements of Income (Unaudited) - Three Months Ended March 31, 2010 and 2009	10

Condensed Consolidated Statements of Cash Flows (Unaudited) - Three Months Ended March 31, 2010 and 2009	11

Public Service Company of New Hampshire and Subsidiaries

Condensed Consolidated Balance Sheets (Unaudited) - March 31, 2010 and December 31, 2009	14

Condensed Consolidated Statements of Income (Unaudited) - Three Months Ended March 31, 2010 and 2009	16

Condensed Consolidated Statements of Cash Flows (Unaudited) - Three Months Ended March 31, 2010 and 2009	17

Western Massachusetts Electric Company and Subsidiary

Condensed Consolidated Balance Sheets (Unaudited) - March 31, 2010 and December 31, 2009	20

Condensed Consolidated Statements of Income (Unaudited) - Three Months Ended March 31, 2010 and 2009	22

Condensed Consolidated Statements of Cash Flows (Unaudited) - Three Months Ended March 31, 2010 and 2009	23

Combined Notes to Condensed Consolidated Financial Statements (Unaudited - all companies)	24

Report of Independent Registered Public Accounting Firm	48

iii


	Page

ITEM 2 - Management's Discussion and Analysis of Financial Condition and Results of Operations for the following companies:

Northeast Utilities and Subsidiaries		49

The Connecticut Light and Power Company and Subsidiaries		64

Public Service Company of New Hampshire and Subsidiaries		66

Western Massachusetts Electric Company and Subsidiary		68

ITEM 3 - Quantitative and Qualitative Disclosures About Market Risk		70

ITEM 4 - Controls and Procedures		70

PART II - OTHER INFORMATION

ITEM 1 - Legal Proceedings		71

ITEM 1A - Risk Factors		71

ITEM 2 - Unregistered Sales of Equity Securities and Use of Proceeds		71

ITEM 6 - Exhibits		72

SIGNATURES		74

NORTHEAST UTILITIES AND SUBSIDIARIES


NORTHEAST UTILITIES AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)

		March 31,		December 31,
(Thousands of Dollars)		2010		2009

ASSETS

Current Assets:
Cash and Cash Equivalents	$	30,012	$	26,952
Receivables, Net		570,870		512,770
Unbilled Revenues		161,872		229,326
Fuel, Materials and Supplies		229,837		277,085
Marketable Securities		81,960		66,236
Derivative Assets		17,379		31,785
Prepayments and Other Current Assets		151,641		123,700
Total Current Assets		1,243,571		1,267,854

Property, Plant and Equipment, Net		8,957,713		8,839,965

Deferred Debits and Other Assets:
Regulatory Assets		3,207,971		3,244,931
Goodwill		287,591		287,591
Marketable Securities		41,763		54,905
Derivative Assets		153,651		189,751
Other Long-Term Assets		213,186		172,682
Total Deferred Debits and Other Assets		3,904,162		3,949,860



Total Assets	$	14,105,446	$	14,057,679



The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.


NORTHEAST UTILITIES AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)

		March 31,		December 31,
(Thousands of Dollars)		2010		2009

LIABILITIES AND CAPITALIZATION

Current Liabilities:
Notes Payable to Banks	$	100,313	$	100,313
Long-Term Debt - Current Portion		66,286		66,286
Accounts Payable		385,181		457,582
Accrued Taxes		64,236		50,246
Accrued Interest		92,879		83,763
Derivative Liabilities		44,208		37,617
Other Current Liabilities		166,138		183,605
Total Current Liabilities		919,241		979,412

Rate Reduction Bonds		375,866		442,436

Deferred Credits and Other Liabilities:
Accumulated Deferred Income Taxes		1,450,931		1,380,143
Accumulated Deferred Investment Tax Credits		21,466		22,145
Regulatory Liabilities		426,687		485,706
Derivative Liabilities		972,041		955,646
Accrued Pension		786,195		781,431
Other Long-Term Liabilities		822,759		823,723
Total Deferred Credits and Other Liabilities		4,480,079		4,448,794

Capitalization:
Long-Term Debt		4,588,862		4,492,935

Noncontrolling Interest in Consolidated Subsidiary:
Preferred Stock Not Subject to Mandatory Redemption		116,200		116,200

Common Shareholders' Equity:
Common Shares		978,381		977,276
Capital Surplus, Paid In		1,763,894		1,762,097
Deferred Contribution Plan		(67)		(2,944)
Retained Earnings		1,287,271		1,246,543
Accumulated Other Comprehensive Loss		(42,740)		(43,467)
Treasury Stock		(361,541)		(361,603)
Common Shareholders' Equity		3,625,198		3,577,902
Total Capitalization		8,330,260		8,187,037

Total Liabilities and Capitalization	$	14,105,446	$	14,057,679


The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.


NORTHEAST UTILITIES AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)

		Three Months Ended March 31,
(Thousands of Dollars, Except Share Information)		2010		2009

Operating Revenues	$	1,339,420	$	1,593,483

Operating Expenses:
Fuel, Purchased and Net Interchange Power		603,349		838,920
Other Operating Expenses		248,273		247,445
Maintenance		45,637		48,836
Depreciation		78,656		76,983
Amortization of Regulatory (Liabilities)/Assets, Net		(8,327)		21,691
Amortization of Rate Reduction Bonds		59,570		55,897
Taxes Other Than Income Taxes		85,599		86,429
Total Operating Expenses		1,112,757		1,376,201
Operating Income		226,663		217,282

Interest Expense:
Interest on Long-Term Debt		57,270		55,684
Interest on Rate Reduction Bonds		6,690		10,625
Other Interest		3,302		4,668
Interest Expense		67,262		70,977
Other Income, Net		8,057		4,182
Income Before Income Tax Expense		167,458		150,487
Income Tax Expense		79,857		51,423
Net Income		87,601		99,064
Net Income Attributable to Noncontrolling Interest:
Preferred Dividends of Subsidiary		1,390		1,390
Net Income Attributable to Controlling Interest	$	86,211	$	97,674

Basic and Fully Diluted Earnings Per Common Share	$	0.49	$	0.60

Dividends Declared Per Common Share	$	0.26	$	0.24

Weighted Average Common Shares Outstanding:
Basic		176,349,762		162,340,475
Fully Diluted		176,537,472		162,925,167

The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.


NORTHEAST UTILITIES AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
		Three Months Ended March 31,
(Thousands of Dollars)		2010		2009

Operating Activities:
Net Income	$	87,601	$	99,064
Adjustments to Reconcile Net Income to Net Cash Flows
Provided by Operating Activities:
Bad Debt Expense		9,556		9,507
Depreciation		78,656		76,983
Deferred Income Taxes		33,248		17,178
Pension and PBOP Expense, Net of Capitalized Portion and PBOP Contributions		23,331		6,703
Regulatory Overrecoveries/(Underrecoveries), Net		6,066		(14,694)
Amortization of Regulatory (Liabilities)/Assets, Net		(8,327)		21,691
Amortization of Rate Reduction Bonds		59,570		55,897
Deferred Contractual Obligations		(6,274)		(8,666)
Derivative Assets and Liabilities		(2,594)		(14,769)
Other		(35,160)		(3,450)
Changes in Current Assets and Liabilities:
Receivables and Unbilled Revenues, Net		(7,258)		10,483
Fuel, Materials and Supplies		48,431		51,171
Taxes Receivable/Accrued		4,639		43,270
Other Current Assets		(279)		(1,541)
Accounts Payable		(46,188)		(174,497)
Counterparty Deposits and Margin Special Deposits		(12,946)		(10,582)
Other Current Liabilities		(6,369)		(23,795)
Net Cash Flows Provided by Operating Activities		225,703		139,953

Investing Activities:
Investments in Property and Plant		(202,487)		(208,896)
Proceeds from Sales of Marketable Securities		21,331		52,933
Purchases of Marketable Securities		(21,825)		(54,557)
Rate Reduction Bond Escrow and Other Deposits		(322)		(1,480)
Other Investing Activities		(156)		2,853
Net Cash Flows Used in Investing Activities		(203,459)		(209,147)

Financing Activities:
Issuance of Common Shares		-		387,350
Cash Dividends on Common Shares		(45,088)		(37,207)
Cash Dividends on Preferred Stock		(1,390)		(1,390)
Decrease in Short-Term Debt		-		(124,909)
Issuance of Long-Term Debt		95,000		250,000
Retirements of Rate Reduction Bonds		(66,569)		(62,451)
Financing Fees		(1,124)		(15,205)
Other Financing Activities		(13)		18
Net Cash Flows (Used in)/Provided by Financing Activities		(19,184)		396,206
Net Increase in Cash and Cash Equivalents		3,060		327,012
Cash and Cash Equivalents - Beginning of Period		26,952		89,816
Cash and Cash Equivalents - End of Period	$	30,012	$	416,828

The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

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THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES


THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)

		March 31,		December 31,
(Thousands of Dollars)		2010		2009

ASSETS

Current Assets:
Cash	$	3,527	$	45
Receivables, Net		349,152		327,969
Accounts Receivable from Affiliated Companies		4,552		2,362
Notes Receivable from Affiliated Companies		34,675		97,775
Unbilled Revenues		94,134		140,632
Materials and Supplies		62,917		65,623
Derivative Assets		8,132		24,593
Prepayments and Other Current Assets		40,807		18,385
Total Current Assets		597,896		677,384

Property, Plant and Equipment, Net		5,386,314		5,340,561

Deferred Debits and Other Assets:
Regulatory Assets		2,041,668		2,068,778
Derivative Assets		137,825		183,231
Other Long-Term Assets		106,623		94,610
Total Deferred Debits and Other Assets		2,286,116		2,346,619



Total Assets	$	8,270,326	$	8,364,564



The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.


THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
		March 31,		December 31,
(Thousands of Dollars)		2010		2009

LIABILITIES AND CAPITALIZATION

Current Liabilities:
Long-Term Debt - Current Portion	$	62,000	$	62,000
Accounts Payable		197,199		242,853
Accounts Payable to Affiliated Companies		53,042		48,795
Accrued Taxes		46,063		36,860
Accrued Interest		46,572		49,867
Derivative Liabilities		13,488		9,770
Other Current Liabilities		94,168		100,846
Total Current Liabilities		512,532		550,991

Rate Reduction Bonds		144,901		195,587

Deferred Credits and Other Liabilities:
Accumulated Deferred Income Taxes		942,858		901,527
Accumulated Deferred Investment Tax Credits		15,791		16,355
Regulatory Liabilities		263,124		316,160
Derivative Liabilities		922,977		913,349
Accrued Pension		47,338		51,319
Other Long-Term Liabilities		399,526		409,532
Total Deferred Credits and Other Liabilities		2,591,614		2,608,242

Capitalization:
Long-Term Debt		2,520,518		2,520,361

Preferred Stock Not Subject to Mandatory Redemption		116,200		116,200

Common Stockholder's Equity:
Common Stock		60,352		60,352
Capital Surplus, Paid In		1,601,879		1,601,792
Retained Earnings		725,383		714,210
Accumulated Other Comprehensive Loss		(3,053)		(3,171)
Common Stockholder's Equity		2,384,561		2,373,183
Total Capitalization		5,021,279		5,009,744

Total Liabilities and Capitalization	$	8,270,326	$	8,364,564


The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.


THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
		Three Months Ended March 31,
(Thousands of Dollars)		2010		2009

Operating Revenues	$	794,980	$	954,503

Operating Expenses:
Fuel, Purchased and Net Interchange Power		362,820		514,386
Other Operating Expenses		134,813		139,411
Maintenance		21,838		27,115
Depreciation		47,525		46,433
Amortization of Regulatory Assets, Net		1,671		13,007
Amortization of Rate Reduction Bonds		43,283		40,557
Taxes Other Than Income Taxes		57,531		58,189
Total Operating Expenses		669,481		839,098
Operating Income		125,499		115,405

Interest Expense:
Interest on Long-Term Debt		33,632		31,686
Interest on Rate Reduction Bonds		3,032		5,799
Other Interest		1,863		209
Interest Expense		38,527		37,694
Other Income, Net		4,933		2,708
Income Before Income Tax Expense		91,905		80,419
Income Tax Expense		43,493		27,284
Net Income	$	48,412	$	53,135


The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.


THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
		Three Months Ended March 31,
(Thousands of Dollars)		2010		2009

Operating Activities:
Net Income	$	48,412	$	53,135
Adjustments to Reconcile Net Income to Net Cash Flows
Provided by Operating Activities:
Bad Debt Expense		2,832		2,644
Depreciation		47,525		46,433
Deferred Income Taxes		18,956		19,240
Pension and PBOP Expense/(Income), Net of Capitalized Portion and PBOP Contributions		3,602		(2,437)
Regulatory Underrecoveries, Net		(230)		(25,050)
Amortization of Regulatory Assets, Net		1,671		13,007
Amortization of Rate Reduction Bonds		43,283		40,557
Deferred Contractual Obligations		(4,304)		(5,730)
Other		(17,127)		(3,062)
Changes in Current Assets and Liabilities:
Receivables and Unbilled Revenues, Net		8,773		29,919
Materials and Supplies		2,706		(974)
Taxes Receivable/Accrued		340		33,199
Other Current Assets		(10,122)		(9,736)
Accounts Payable		(25,350)		(55,938)
Other Current Liabilities		2,872		(13,638)
Net Cash Flows Provided by Operating Activities		123,839		121,569

Investing Activities:
Investments in Property and Plant		(97,725)		(116,325)
Decrease/(Increase) in NU Money Pool Lending		63,100		(28,488)
Rate Reduction Bond Escrow and Other Deposits		2,289		(2,185)
Other Investing Activities		(14)		1,491
Net Cash Flows Used in Investing Activities		(32,350)		(145,507)

Financing Activities:
Cash Dividends on Common Stock		(35,849)		(28,462)
Cash Dividends on Preferred Stock		(1,390)		(1,390)
Decrease in Short-Term Debt		-		(74,001)
Decrease in NU Money Pool Borrowings		-		(102,725)
Capital Contributions from NU Parent		-		39,000
Issuance of Long-Term Debt		-		250,000
Retirements of Rate Reduction Bonds		(50,686)		(47,493)
Other Financing Activities		(82)		(2,784)
Net Cash Flows (Used in)/Provided by Financing Activities		(88,007)		32,145
Net Increase in Cash		3,482		8,207
Cash - Beginning of Period		45		-
Cash - End of Period	$	3,527	$	8,207

The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

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PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES


PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
		March 31,		December 31,
(Thousands of Dollars)		2010		2009

ASSETS

Current Assets:
Cash	$	2,247	$	1,974
Receivables, Net		93,481		89,337
Accounts Receivable from Affiliated Companies		1,583		286
Unbilled Revenues		41,043		49,358
Taxes Receivable		16,325		22,600
Fuel, Materials and Supplies		113,660		127,447
Prepayments and Other Current Assets		29,050		36,387
Total Current Assets		297,389		327,389

Property, Plant and Equipment, Net		1,856,891		1,814,714

Deferred Debits and Other Assets:
Regulatory Assets		497,709		494,077
Other Long-Term Assets		83,458		61,011
Total Deferred Debits and Other Assets		581,167		555,088



Total Assets	$	2,735,447	$	2,697,191



The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.


PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)

		March 31,		December 31,
(Thousands of Dollars)		2010		2009

LIABILITIES AND CAPITALIZATION

Current Liabilities:
Notes Payable to Affiliated Companies	$	12,400	$	26,700
Accounts Payable		103,778		109,521
Accounts Payable to Affiliated Companies		23,824		20,083
Accrued Interest		16,803		10,255
Derivative Liabilities		25,484		18,785
Other Current Liabilities		25,263		27,983
Total Current Liabilities		207,552		213,327

Rate Reduction Bonds		176,151		188,113

Deferred Credits and Other Liabilities:
Accumulated Deferred Income Taxes		290,724		275,669
Accumulated Deferred Investment Tax Credits		190		211
Regulatory Liabilities		69,732		69,872
Derivative Liabilities		9,691		7,635
Accrued Pension		277,885		272,905
Other Long-Term Liabilities		113,104		105,759
Total Deferred Credits and Other Liabilities		761,326		732,051

Capitalization:
Long-Term Debt		836,282		836,255

Common Stockholder's Equity:
Common Stock		-		-
Capital Surplus, Paid In		443,660		420,169
Retained Earnings		311,153		307,988
Accumulated Other Comprehensive Loss		(677)		(712)
Common Stockholder's Equity		754,136		727,445
Total Capitalization		1,590,418		1,563,700

Total Liabilities and Capitalization	$	2,735,447	$	2,697,191


The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.


PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
		Three Months Ended March 31,
(Thousands of Dollars)		2010		2009

Operating Revenues	$	258,568	$	307,653

Operating Expenses:
Fuel, Purchased and Net Interchange Power		103,771		146,225
Other Operating Expenses		63,125		62,728
Maintenance		16,002		15,522
Depreciation		15,968		15,171
Amortization of Regulatory (Liabilities)/Assets, Net		(5,694)		7,947
Amortization of Rate Reduction Bonds		12,391		11,686
Taxes Other Than Income Taxes		13,079		12,244
Total Operating Expenses		218,642		271,523
Operating Income		39,926		36,130

Interest Expense:
Interest on Long-Term Debt		9,512		8,104
Interest on Rate Reduction Bonds		2,721		3,658
Other Interest		179		792
Interest Expense		12,412		12,554
Other Income, Net		2,412		1,425
Income Before Income Tax Expense		29,926		25,001
Income Tax Expense		14,116		7,506
Net Income	$	15,810	$	17,495



The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.


PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
		Three Months Ended March 31,
(Thousands of Dollars)		2010		2009

Operating Activities:
Net Income	$	15,810	$	17,495
Adjustments to Reconcile Net Income to Net Cash Flows
Provided by Operating Activities:
Bad Debt Expense		2,496		1,628
Depreciation		15,968		15,171
Deferred Income Taxes		8,474		(7,981)
Pension and PBOP Expense, Net of Capitalized Portion and PBOP Contributions		6,911		4,143
Regulatory (Underrecoveries)/Overrecoveries, Net		(2,073)		3,413
Amortization of Regulatory (Liabilities)/Assets, Net		(5,694)		7,947
Amortization of Rate Reduction Bonds		12,391		11,686
Deferred Contractual Obligations		(782)		(1,394)
Other		(14,937)		886
Changes in Current Assets and Liabilities:
Receivables and Unbilled Revenues, Net		378		(13,111)
Fuel, Materials and Supplies		14,971		4,921
Taxes Receivable/Accrued		6,275		19,279
Other Current Assets		11,078		8,170
Accounts Payable		(1,599)		(66,171)
Other Current Liabilities		3,007		5,990
Net Cash Flows Provided by Operating Activities		72,674		12,072

Investing Activities:
Investments in Property and Plant		(54,139)		(52,531)
Decrease in NU Money Pool Lending		-		48,200
Other Investing Activities		(2,760)		(378)
Net Cash Flows Used in Investing Activities		(56,899)		(4,709)

Financing Activities:
Cash Dividends on Common Stock		(12,645)		(10,211)
Decrease in NU Money Pool Borrowings		(14,300)		-
Capital Contributions from NU Parent		23,456		15,000
Retirements of Rate Reduction Bonds		(11,962)		(11,278)
Other Financing Activities		(51)		(113)
Net Cash Flows Used in Financing Activities		(15,502)		(6,602)
Net Increase in Cash		273		761
Cash - Beginning of Period		1,974		195
Cash - End of Period	$	2,247	$	956

The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

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WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY


WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)

		March 31,		December 31,
(Thousands of Dollars)		2010		2009

ASSETS

Current Assets:
Cash	$	1	$	1
Receivables, Net		41,030		38,415
Accounts Receivable from Affiliated Companies		1,164		191
Notes Receivable from Affiliated Companies		5,700		-
Unbilled Revenues		13,175		16,090
Taxes Receivable		4,321		4,192
Materials and Supplies		9,363		8,314
Marketable Securities		41,576		28,261
Prepayments and Other Current Assets		1,462		1,774
Total Current Assets		117,792		97,238

Property, Plant and Equipment, Net		721,435		705,760

Deferred Debits and Other Assets:
Regulatory Assets		235,240		240,804
Marketable Securities		15,252		28,500
Other Long-Term Assets		33,691		29,498
Total Deferred Debits and Other Assets		284,183		298,802



Total Assets	$	1,123,410	$	1,101,800



The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.


WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)

		March 31,		December 31,
(Thousands of Dollars)		2010		2009

LIABILITIES AND CAPITALIZATION

Current Liabilities:
Notes Payable to Affiliated Companies	$	-	$	136,100
Accounts Payable		36,594		36,680
Accounts Payable to Affiliated Companies		9,699		7,924
Accrued Interest		2,002		5,274
Other Current Liabilities		7,716		8,873
Total Current Liabilities		56,011		194,851

Rate Reduction Bonds		54,815		58,735

Deferred Credits and Other Liabilities:
Accumulated Deferred Income Taxes		215,571		211,391
Accumulated Deferred Investment Tax Credits		1,499		1,499
Regulatory Liabilities		19,643		21,683
Other Long-Term Liabilities		60,822		61,359
Total Deferred Credits and Other Liabilities		297,535		295,932

Capitalization:
Long-Term Debt		400,165		305,475

Common Stockholder's Equity:
Common Stock		10,866		10,866
Capital Surplus, Paid In		211,556		145,400
Retained Earnings		92,487		90,549
Accumulated Other Comprehensive Loss		(25)		(8)
Common Stockholder's Equity		314,884		246,807
Total Capitalization		715,049		552,282

Total Liabilities and Capitalization	$	1,123,410	$	1,101,800


The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.


WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)

		Three Months Ended March 31,
(Thousands of Dollars)		2010		2009

Operating Revenues	$	100,207	$	118,081

Operating Expenses:
Fuel, Purchased and Net Interchange Power		43,632		63,235
Other Operating Expenses		23,226		22,664
Maintenance		4,542		3,106
Depreciation		5,953		5,528
Amortization of Regulatory (Liabilities)/Assets, Net		(1,570)		670
Amortization of Rate Reduction Bonds		3,895		3,654
Taxes Other Than Income Taxes		4,084		3,897
Total Operating Expenses		83,762		102,754
Operating Income		16,445		15,327

Interest Expense:
Interest on Long-Term Debt		3,881		3,443
Interest on Rate Reduction Bonds		937		1,168
Other Interest		126		627
Interest Expense		4,944		5,238
Other Income/(Loss), Net		604		(154)
Income Before Income Tax Expense		12,105		9,935
Income Tax Expense		6,446		3,789
Net Income	$	5,659	$	6,146



The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.


WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
		Three Months Ended March 31,
(Thousands of Dollars)			2010		2009

Operating Activities:
Net Income	$		5,659	$	6,146
Adjustments to Reconcile Net Income to Net Cash Flows
Provided by/(Used in) Operating Activities:
Bad Debt Expense			1,567		2,217
Depreciation			5,953		5,528
Deferred Income Taxes			2,935		2,033
Pension and PBOP Expense/(Income), Net of Capitalized Portion and PBOP Contributions			565		(621)
Regulatory Underrecoveries, Net			(2,748)		(1,099)
Amortization of Regulatory (Liabilities)/Assets, Net			(1,570)		670
Amortization of Rate Reduction Bonds			3,895		3,654
Deferred Contractual Obligations			(1,187)		(1,543)
Other			722		(1,353)
Changes in Current Assets and Liabilities:
Receivables and Unbilled Revenues, Net			(1,768)		(1,981)
Materials and Supplies			(1,049)		(59)
Taxes Receivable/Accrued			(129)		4,016
Accounts Payable			(75)		(20,148)
Other Current Assets and Liabilities			(4,019)		(5,348)
Net Cash Flows Provided by/(Used in) Operating Activities			8,751		(7,888)

Investing Activities:
Investments in Property and Plant			(19,111)		(19,230)
Proceeds from Sales of Marketable Securities			11,086		35,722
Purchases of Marketable Securities			(11,175)		(36,517)
Increase in NU Money Pool Lending			(5,700)		-
Other Investing Activities			(123)		369
Net Cash Flows Used in Investing Activities			(25,023)		(19,656)

Financing Activities:
Cash Dividends on Common Stock			(3,721)		(7,550)
Increase in Short-Term Debt			-		45,227
Issuance of Long-Term Debt			95,000		-
Decrease in NU Money Pool Borrowings			(136,100)		(4,800)
Retirements of Rate Reduction Bonds			(3,921)		(3,679)
Capital Contributions from NU Parent			66,143		-
Financing Fees			(1,124)		-
Other Financing Activities			(5)		(10)
Net Cash Flows Provided by Financing Activities			16,272		29,188
Net Increase in Cash			-		1,644
Cash - Beginning of Period			1		-
Cash - End of Period	$		1	$	1,644

The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

NORTHEAST UTILITIES AND SUBSIDIARIES

THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES

WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Presentation

Certain information and footnote disclosures normally included in annual consolidated financial statements prepared in accordance with GAAP have been omitted pursuant to the rules and regulations of the SEC. The accompanying unaudited condensed consolidated financial statements should be read in conjunction with the entirety of this combined Quarterly Report on Form 10-Q and the combined 2009 Annual Report on Form 10-K of Northeast Utilities (NU or the Company), CL&P, PSNH, and WMECO, which was filed with the SEC (NU 2009 Form 10-K). The accompanying unaudited condensed consolidated financial statements contain, in the opinion of management, all adjustments (including normal, recurring adjustments) necessary to present fairly NU's and the above companies' financial positions as of March 31, 2010 and December 31, 2009, and the results of operations and cash flows for the three months ended March 31, 2010 and 2009. The results of operations and cash flows for the three months ended March 31, 2010 and 2009 are not necessarily indicative of the results expected for a full year.

Refer to the Glossary of Terms included in this combined Quarterly Report on Form 10-Q for abbreviations and acronyms used throughout the combined notes to the unaudited condensed consolidated financial statements.

The unaudited condensed consolidated financial statements of NU, CL&P, PSNH and WMECO include the accounts of all their respective subsidiaries. Intercompany transactions have been eliminated in consolidation.

In accordance with accounting guidance on the consolidation of VIEs, the Company evaluates its variable interests to determine if it has a controlling financial interest in a VIE that would require consolidation. The Company’s variable interests primarily include contracts with developers of power plants that are required by regulation and provide for regulatory recovery of contract costs and benefits through customer rates. The Company would consolidate a VIE if it had both the power to direct the activities of a VIE that most significantly impact the entity’s economic performance and the obligation to absorb losses of or receive benefits from the entity that could potentially be significant to the VIE.

For each variable interest, NU evaluates the activities of the power plant that most significantly impact the VIE’s economic performance to determine whether it has control over those activities. NU’s assessment of control includes an analysis of who operates and maintains the power plant including dispatch rights and who controls the activities of the power plant after the expiration of its power purchase agreement with NU. NU also evaluates its exposure to potentially significant losses and benefits of the VIE. As of March 31, 2010, NU held variable interests in VIEs through agreements with certain entities that are single power plant owners of renewable energy, peaking generation and other independent power producers. NU does not control the activities that are economically significant to these VIEs or provide financial or other support to these VIEs. NU does not have financial exposure because the costs and benefits of all of these arrangements are fully recoverable from or refundable to NU’s customers. As of March 31, 2010, NU was not identified as the primary beneficiary of any power plant VIEs. Therefore, the company does not consolidate any VIEs. The Company does not have any variable interest in a VIE that is material to the accompanying unaudited condensed consolidated financial statements.

The preparation of the unaudited condensed consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent liabilities as of the date of the unaudited condensed consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Certain reclassifications of prior period data were made in the accompanying unaudited condensed consolidated balance sheets for CL&P, PSNH, and WMECO and the statements of cash flows for NU, PSNH, and WMECO. These reclassifications were made to conform to the current period's presentation.

NU evaluates events and transactions that occur after the balance sheet date but before financial statements are issued and recognizes in the financial statements the effects of all subsequent events that provide additional evidence about conditions that existed as of the balance sheet date and discloses but does not recognize in the financial statements subsequent events that provide evidence about the conditions that arose after the balance sheet date but before the financial statements are issued. See Note 12, "Subsequent Events," for further information.

Fair Value Measurements

NU, including CL&P, PSNH, and WMECO, applies fair value measurement guidance to the Regulated and unregulated companies' derivative contracts recorded at fair value and to the marketable securities held in the NU supplemental benefit trust and WMECO's spent nuclear fuel trust. Fair value measurement guidance is also applied to investment valuations used to calculate the funded status

of NU's Pension and PBOP plans and non-recurring fair value measurements of NU's non-financial assets and liabilities, such as AROs and Yankee Gas' goodwill.

Fair Value Hierarchy: In measuring fair value, NU uses observable market data when available and minimizes the use of unobservable inputs. Unobservable inputs are needed to value certain derivative contracts due to complexities in the terms of the contracts. Inputs used in fair value measurements are categorized into three fair value hierarchy levels for disclosure purposes. The entire fair value measurement is categorized based on the lowest level of input that is significant to the fair value measurement. NU evaluates the classification of assets and liabilities measured at fair value on a quarterly basis, and NU’s policy is to recognize transfers between levels of the fair value hierarchy as of the end of the reporting period. The three levels of the fair value hierarchy are described below:

Level 1 - Inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis.

Level 2 - Inputs are quoted prices for similar instruments in active markets, quoted prices for identical or similar instruments in markets that are not active, and model-derived valuations in which all significant inputs are observable.

Level 3 - Quoted market prices are not available. Fair value is derived from valuation techniques in which one or more significant inputs or assumptions are unobservable. Where possible, valuation techniques incorporate observable market inputs that can be validated to external sources such as industry exchanges, including prices of energy and energy-related products. Significant unobservable inputs are used in the valuations, including items such as energy and energy-related product prices in future years for which observable prices are not yet available, future contract quantities under full-requirements or supplemental sales contracts, and market volatilities. Items valued using these valuation techniques are classified according to the lowest level for which there is at least one input that is significant to the valuation. Therefore, an item may be classified in Level 3 even though there may be some significant inputs that are readily observable.

Determination of Fair Value: The valuation techniques and inputs used in NU's fair value measurements are described in Note 2, "Derivative Instruments," and Note 9, "Marketable Securities," to the unaudited condensed consolidated financial statements. There were no changes to the valuation methodologies for derivative instruments or marketable securities for the three months ended March 31, 2010 and December 31, 2009.

Regulatory Accounting

The transmission and distribution segments of CL&P, PSNH (including its generation business) and WMECO, along with Yankee Gas' distribution segment (collectively, the Regulated companies), continue to be rate-regulated on a cost-of-service basis, therefore, the accounting policies of the Regulated companies conform to GAAP applicable to rate-regulated enterprises and historically reflect the effects of the rate-making process.

Management believes it is probable that the Regulated companies will recover their respective investments in long-lived assets, including regulatory assets. All material net regulatory assets are earning an equity return, except for the majority of deferred benefit cost assets, regulatory assets offsetting derivative liabilities, securitized regulatory assets and income tax assets, which are not supported by equity. Amortization and deferrals of regulatory assets/(liabilities) are primarily included on a net basis in Amortization of regulatory assets/(liabilities), net on the accompanying unaudited condensed consolidated statements of income.

Regulatory Assets: The components of regulatory assets are as follows:


	As of March 31, 2010		As of December 31, 2009
(Millions of Dollars)	NU		NU
Deferred benefit costs	$	1,111.0	$	1,132.1
Regulatory assets offsetting derivative liabilities		872.2		855.6
Securitized assets		366.0		432.9
Income taxes, net		372.7		363.2
Unrecovered contractual obligations		144.2		149.5
Regulatory tracker deferrals		131.0		104.1
Storm cost deferral		64.9		60.0
Asset retirement obligations		43.7		42.9
Losses on reacquired debt		23.3		24.0
Environmental costs		31.6		24.6
Other regulatory assets		47.4		56.0
Totals	$	3,208.0	$	3,244.9


	As of March 31, 2010						As of December 31, 2009
(Millions of Dollars)	CL&P		PSNH		WMECO		CL&P		PSNH		WMECO
Deferred benefit costs	$	493.3	$	150.7	$	103.1	$	502.4	$	154.2	$	104.9
Regulatory assets offsetting derivative liabilities		836.3		35.2		-		828.6		26.4		-
Securitized assets		144.8		167.7		53.5		195.4		180.1		57.4
Income taxes, net		309.0		25.2		17.2		304.1		21.9		16.9
Unrecovered contractual obligations		113.8		-		30.4		118.0		-		31.5
Regulatory tracker deferrals		90.8		22.0		15.2		70.3		19.0		11.3
Storm cost deferral		5.7		48.7		10.5		-		50.8		9.2
Asset retirement obligations		24.4		14.2		2.8		23.8		14.0		2.8
Losses on reacquired debt		12.3		9.0		0.4		12.7		9.2		0.4
Environmental costs		-		8.7		-		-		1.3		-
Other regulatory assets		11.3		16.3		2.1		13.5		17.2		6.4
Totals	$	2,041.7	$	497.7	$	235.2	$	2,068.8	$	494.1	$	240.8

Additionally, the Regulated companies had $72.6 million ($24.8 million for CL&P, $25.3 million for PSNH, and $11.5 million for WMECO) and $27.1 million ($9.9 million for CL&P and $9.1 million for WMECO) of regulatory costs as of March 31, 2010 and December 31, 2009, respectively, which were included in Other long-term assets on the accompanying unaudited condensed consolidated balance sheets. These amounts represent incurred costs that have not yet been approved for recovery by the applicable regulatory agency. Of the total March 31, 2010 amount, $24.4 million ($13.7 million for CL&P, $5.3 million for PSNH, and $2.8 million for WMECO) relates to the 2010 Healthcare Act. For further information, see Note 1I, "Summary of Significant Accounting Policies - Income Taxes," to the unaudited condensed consolidated financial statements. The $25.3 million at PSNH also includes $20 million of costs incurred for the February 2010 winter storm restorations that met the NHPUC specified criteria for deferral to a major storm cost reserve. Management believes these costs are probable of recovery in future cost-of-service regulated rates.

CL&P deferred $14.2 million of costs for the March 2010 winter storm restorations that met the DPUC criteria for a major storm. CL&P is allowed to collect from customers $3 million per year for major storm costs. Of the $14.2 million, CL&P had previously collected $8.5 million from customers and has established a regulatory asset for the remaining $5.7 million of storm costs.

Regulatory Liabilities: The components of regulatory liabilities are as follows:


	As of March 31, 2010		As of December 31, 2009
(Millions of Dollars)	NU		NU
Cost of removal	$	209.6	$	209.2
Regulatory liabilities offsetting derivative assets		42.9		109.4
Regulatory tracker deferrals		72.6		62.5
AFUDC transmission incentive (Note 1F)		52.4		51.1
Pension and PBOP liabilities - Yankee Gas acquisition		14.4		15.0
Overrecovered natural gas costs		7.4		7.1
Other regulatory liabilities		27.4		31.4
Totals	$	426.7	$	485.7


	As of March 31, 2010						As of December 31, 2009
(Millions of Dollars)	CL&P		PSNH		WMECO		CL&P		PSNH		WMECO
Cost of removal	$	82.5	$	61.0	$	16.1	$	82.2	$	60.5	$	16.6
Regulatory liabilities offsetting derivative assets		42.9		-		-		109.0		0.4		-
Regulatory tracker deferrals		66.9		5.7		-		56.0		4.4		2.1
AFUDC transmission incentive (Note 1F)		51.6		-		0.8		50.4		-		0.7
WMECO provision for rate refunds		-		-		2.0		-		-		2.0
Other regulatory liabilities		19.2		3.0		0.7		18.6		4.6		0.3
Totals	$	263.1	$	69.7	$	19.6	$	316.2	$	69.9	$	21.7

Property, Plant and Equipment and Accumulated Depreciation

The following tables summarize the NU, CL&P, PSNH, and WMECO investments in utility plant as of March 31, 2010 and December 31, 2009:


	As of March 31,		As of December 31,
	2010		2009
(Millions of Dollars)	NU		NU
Distribution – electric	$	5,963.7	$	5,893.9
Distribution - natural gas		1,081.8		1,071.1
Transmission		3,227.5		3,219.2
Generation		658.1		660.1
Electric and natural gas utility		10,931.1		10,844.3
Other ⁽¹⁾		269.7		265.6
Total property, plant and equipment, gross		11,200.8		11,109.9
Less: accumulated depreciation
Electric and natural gas utility		(2,765.6)		(2,721.3)
Other		(123.7)		(120.3)
Total accumulated depreciation		(2,889.3)		(2,841.6)
Net property, plant and equipment		8,311.5		8,268.3
Construction work in progress		646.2		571.7
Total property, plant and equipment, net	$	8,957.7	$	8,840.0

⁽¹⁾

These assets primarily relate to RRR ($144.4 million and $143.8 million) and NUSCO ($112.5 million and $109 million) as of March 31, 2010 and December 31, 2009, respectively.


	As of March 31, 2010						As of December 31, 2009
(Millions of Dollars)	CL&P		PSNH		WMECO		CL&P		PSNH		WMECO
Distribution	$	4,012.8	$	1,317.1	$	664.6	$	3,960.1	$	1,309.2	$	654.9
Transmission		2,578.1		449.6		199.8		2,573.2		450.2		195.7
Generation		-		658.1		-		-		660.1		-
Total property, plant and equipment, gross		6,590.9		2,424.8		864.4		6,533.3		2,419.5		850.6
Less: accumulated depreciation		(1,452.3)		(811.4)		(225.8)		(1,426.6)		(805.5)		(218.2)
Net property, plant and equipment		5,138.6		1,613.4		638.6		5,106.7		1,614.0		632.4
Construction work in progress		247.7		243.5		82.8		233.9		200.7		73.4
Total property, plant and equipment, net	$	5,386.3	$	1,856.9	$	721.4	$	5,340.6	$	1,814.7	$	705.8

Provision for Uncollectible Accounts

NU, including CL&P, PSNH and WMECO, maintain a provision for uncollectible accounts to record their receivables at an estimated net realizable value. This provision is determined based upon a variety of factors, including applying an estimated uncollectible account percentage to each receivable aging category, historical collection and write-off experience and management’s assessment of collectibility from individual customers. Management reviews at least quarterly the collectibility of the receivables, and if circumstances change, collectibility estimates are adjusted accordingly. Receivable balances are written-off against the provision for uncollectible accounts when these balances are deemed to be uncollectible and the accounts are terminated.

The provision for uncollectible accounts as of March 31, 2010 and December 31, 2009, which are included in Receivables, net on the accompanying unaudited condensed consolidated balance sheets, were as follows:


(Millions of Dollars)	As of March 31, 2010		As of December 31, 2009
NU	$	57.2	$	55.3
CL&P		27.1		26.1
PSNH		5.7		5.1
WMECO		7.5		7.2

Allowance for Funds Used During Construction

AFUDC is included in the cost of the Regulated companies' utility plant and represents the cost of borrowed and equity funds used to finance construction. The portion of AFUDC attributable to borrowed funds is recorded as a reduction of Other interest expense, and the AFUDC related to equity funds is recorded as Other income, net on the accompanying unaudited condensed consolidated statements of income.


	For the Three Months Ended
	March 31, 2010		March 31, 2009
(Millions of Dollars, except percentages)	NU		NU
AFUDC:
Borrowed funds	$	1.9	$	2.1
Equity funds		3.1		0.9
Totals	$	5.0	$	3.0
Average AFUDC rates		6.5%		5.2%


	For the Three Months Ended
	March 31, 2010						March 31, 2009
(Millions of Dollars, except percentages)	CL&P		PSNH		WMECO		CL&P		PSNH		WMECO
AFUDC:
Borrowed funds	$	0.7	$	1.2	$	-	$	0.9	$	0.9	$	0.1
Equity funds		1.2		1.9		-		-		0.9		-
Totals	$	1.9	$	3.1	$	-	$	0.9	$	1.8	$	0.1
Average AFUDC rates		8.0%		6.3%		0.4%		3.2%		8.1%		3.8%

The Regulated companies' average AFUDC rate is based on a FERC-prescribed formula that produces an average rate using the cost of a company's short-term financings as well as a company's capitalization (preferred stock, long-term debt and common equity). The average rate is applied to average eligible CWIP amounts to calculate AFUDC. AFUDC is recorded on 100 percent of CL&P's and WMECO's CWIP for their NEEWS projects, all of which is being reserved as a regulatory liability to reflect current rate base recovery for 100 percent of the CWIP as a result of FERC-approved transmission incentives.

Other Income, Net

The pre-tax components of other income/(loss) items are as follows:


	For the Three Months Ended
	March 31, 2010		March 31, 2009
(Million of Dollars)	NU		NU
Other Income:
Investment income	$	1.9	$	1.3
Interest income		0.8		0.8
AFUDC - equity funds		3.1		0.9
Energy Independence Act incentives		1.3		3.6
Other		1.0		0.9
Total Other Income		8.1		7.5
Other Loss:
Investment losses		-		(3.2)
Rental expense		-		(0.1)
Total Other Loss		-		(3.3)
Total Other Income, Net	$	8.1	$	4.2


	For the Three Months Ended
	March 31, 2010						March 31, 2009
(Millions of Dollars)	CL&P		PSNH		WMECO		CL&P		PSNH		WMECO
Other Income:
Investment income	$	1.3	$	0.3	$	0.3	$	1.0	$	0.2	$	0.2
Interest income		0.6		0.2		0.1		-		0.8		-
AFUDC - equity funds		1.2		1.9		-		-		0.9		-
Energy Independence Act incentives		1.3		-		-		3.6		-		-
Other		0.5		-		0.2		0.3		-		0.1
Total Other Income		4.9		2.4		0.6		4.9		1.9		0.3
Investment losses		-		-		-		(2.2)		(0.5)		(0.5)
Total Other Income/(Loss), Net	$	4.9	$	2.4	$	0.6	$	2.7	$	1.4	$	(0.2)

Other income - other includes equity in earnings of the Yankee companies and regional transmission companies of $0.3 million and $0.5 million for NU (de minimis amount and $0.1 million for CL&P and de minimis amounts for PSNH and WMECO in both periods) for the three months ended March 31, 2010 and 2009, respectively. Equity in earnings relates to the Company's investments, including investments of CL&P, PSNH and WMECO in Connecticut Yankee Atomic Power Company, Maine Yankee Atomic Power Company, and Yankee Atomic Electric Company, and NU's investments in two regional transmission companies. For the three months ended March 31, 2010 and 2009, income tax expense associated with the equity in earnings was $0.1 million and $0.2 million, respectively, for NU (de minimis amounts for CL&P, PSNH and WMECO in both periods).

Dividends received from the Yankee Companies and the regional transmission companies investments were recorded as a reduction to NU's, including CL&P, PSNH and WMECO, investment. There was a de minimis amount of dividends received for the three months ended March 31, 2010. Dividends received were $2.8 million ($1.5 million for CL&P, $0.2 million for PSNH and $0.4 million for WMECO) for the three months ended March 31, 2009.

Special Deposits and Counterparty Deposits

To the extent NU Enterprises, through Select Energy, requires collateral from counterparties, or the counterparties require collateral from Select Energy, cash is held on deposit by Select Energy or with unaffiliated counterparties and brokerage firms as a part of the total collateral required based on Select Energy's position in transactions with the counterparty. Select Energy's right to use cash collateral is determined by the terms of the related agreements. Key factors affecting the unrestricted status of a portion of this cash collateral include the financial standing of Select Energy and of NU as its credit supporter.

NU, including CL&P, PSNH, and WMECO, records special deposits and counterparty deposits posted under master netting agreements as an offset to a Derivative asset or liability if the related derivatives are recorded in a net position. As of March 31, 2010, Select Energy had $9.5 million of collateral posted under master netting agreements and netted against the fair value of the derivatives. As of December 31, 2009, CL&P and Select Energy had $0.5 million and $2.1 million, respectively, of collateral posted under master netting agreements and netted against the fair value of the derivatives.

Special deposits paid by Select Energy to unaffiliated counterparties and brokerage firms not subject to master netting agreements totaled $33.3 million and $28.1 million as of March 31, 2010 and December 31, 2009, respectively. These amounts are included in Prepayments and other current assets on the accompanying unaudited condensed consolidated balance sheets. There were no counterparty deposits for Select Energy as of March 31, 2010 and December 31, 2009.

NU, CL&P, PSNH and WMECO have established credit policies regarding counterparties to minimize overall credit risk. These policies require an evaluation of potential counterparties, financial condition, collateral requirements and the use of standardized agreements that allow for the netting of positive and negative exposures associated with a single counterparty. These evaluations result in established credit limits prior to entering into a contract. As of March 31, 2010 and December 31, 2009, there were no counterparty deposits for these companies.

Income Taxes

On March 23, 2010, President Obama signed into law the 2010 Healthcare Act. The 2010 Healthcare Act was amended by a Reconciliation Bill signed into law on March 30, 2010. The 2010 Healthcare Act includes a provision that eliminated the tax deductibility of certain PBOP contributions equal to the amount of the federal subsidy received by companies like NU, which sponsor retiree health care benefit plans with a prescription drug benefit that is actuarially equivalent to Medicare Part D. NU recorded approximately $18 million in charges to Income tax expense on the accompanying unaudited condensed consolidated statement of income for the three months ended March 31, 2010 as a result of the 2010 Healthcare Act. This represented the loss of previously recognized Accumulated deferred income tax assets. Since the electric and natural gas distribution companies are cost-of-service and rate regulated, some of these costs are able to be deferred and recovered through future rates. As a result, NU recognized approximately $15 million in after-tax deferrals ($24.4 million pre-tax) in Other long-term assets on the accompanying unaudited condensed consolidated balance sheet as of March 31, 2010 with an offset to Amortization of regulatory (liabilities)/assets, net on the accompanying unaudited condensed consolidated statement of income, which reflects the probable recovery in future rates of these previously recognized lost tax benefits. Therefore, only the net amount of approximately $3 million resulted in an impact to Net income for the three months ended March 31, 2010.

Other Taxes

Certain excise taxes levied by state or local governments are collected by CL&P and Yankee Gas from their respective customers. These excise taxes are shown on a gross basis with collections in revenues and payments in expenses. Gross receipts taxes, franchise taxes and other excise taxes were included in Operating revenues and Taxes other than income taxes on the accompanying unaudited condensed consolidated statements of income as follows:


	For the Three Months Ended
(Millions of Dollars)	March 31, 2010		March 31, 2009
NU	$	34.2	$	39.0
CL&P		27.3		30.9

Certain sales taxes are also collected by CL&P, WMECO, and Yankee Gas from their respective customers as agents for state and local governments and are recorded on a net basis with no impact on the accompanying unaudited condensed consolidated statements of income.

Common Shares

The following table provides the amount of NU common shares and the shares of CL&P, PSNH and WMECO common stock authorized and issued and the related par values as of March 31, 2010 and December 31, 2009:


			Shares
			Authorized	Issued
		Per Share Par Value	As of March 31, 2010 and December 31, 2009	As of March 31, 2010	As of December 31, 2009
NU	$	5	225,000,000	195,676,144	195,455,214
CL&P	$	10	24,500,000	6,035,205	6,035,205
PSNH	$	1	100,000,000	301	301
WMECO	$	25	1,072,471	434,653	434,653

As of March 31, 2010 and December 31, 2009, common shares held in treasury by NU were 19,704,756 and 19,708,136, respectively.

Restricted Cash

As of March 31, 2010 and December 31, 2009, PSNH had $11.4 million and $10 million, respectively, of restricted cash held with a trustee related to insurance proceeds received on bondable property, which was included in Prepayments and other current assets on the accompanying unaudited condensed consolidated balance sheets.

Supplemental Cash Flow Information

Non-cash investing activities include capital expenditures incurred but not paid as follows:


(Millions of Dollars)	As of March 31, 2010		As of December 31, 2009
NU	$	98.4	$	125.5
CL&P		30.5		48.2
PSNH		45.9		46.5
WMECO		11.8		10.3

The majority of the short-term borrowings of NU, including CL&P, PSNH, and WMECO, have original maturities of three months or less. Accordingly, borrowings and repayments are shown net on the statement of cash flows. In December 2008, NU parent borrowed $127 million under its revolving credit agreement that had original maturities in excess of 90 days. These amounts were repaid in March 2009. This activity is included in the net activity seen in the statement of cash flows. For the three month period ended March 31, 2010, NU, CL&P, PSNH, and WMECO had no such borrowings.

DERIVATIVE INSTRUMENTS

The costs and benefits of derivative contracts that meet the definition of and are designated as "normal purchases or normal sales" (normal) are recognized in Operating expenses or Operating revenues on the accompanying unaudited condensed consolidated statements of income, as applicable, as electricity or natural gas is delivered.

Derivative contracts that are not recorded as normal under the applicable accounting guidance, are recorded at fair value as current or long-term derivative assets or liabilities. Changes in fair values of NU Enterprises' derivatives are included in Net income. For the Regulated companies, including CL&P, PSNH, and Yankee Gas, regulatory assets or liabilities are recorded for the changes in fair values of derivatives, as these contracts are part of current regulated operating costs, or have an allowed recovery mechanism, and management believes that these costs will continue to be recovered from or refunded to customers in cost-of-service, regulated rates. See below for discussion of "Derivatives not designated as hedges."

CL&P, PSNH, WMECO, and Yankee Gas are exposed to the volatility of the prices of energy and energy-related products in procuring energy supply for their customers. The costs associated with supplying energy to customers are recoverable through customer rates. The Company manages the risks associated with the price volatility of energy and energy-related products through the use of derivative contracts, many of which are accounted for as normal (for WMECO all derivative contracts are accounted for as normal) and the use of nonderivative contracts.

CL&P mitigates the risks associated with the price volatility of energy and energy-related products through the use of standard or last resort service contracts, which fix the price of electricity purchased for customers for periods of time ranging from three months to three years and are accounted for as normal. CL&P has entered into derivatives, including FTR contracts and bilateral basis swaps, to manage the risk of congestion costs associated with its SS and LRS contracts. As required by regulation, CL&P has also entered into derivative and nonderivative contracts for the purchase of energy and energy-related products and contracts related to capacity. While the risks managed by these contracts are regional congestion costs and capacity price risks that are not specific to CL&P, Connecticut's electric distribution companies, including CL&P, are required to enter into these contracts. Management believes any costs or benefits from these contracts are recoverable from or refunded to CL&P's customers, and, therefore any changes in fair value are recorded as Regulatory assets and Regulatory liabilities on the accompanying unaudited condensed consolidated balance sheets.

WMECO mitigates the risks associated with the volatility of the prices of energy and energy-related products in procuring energy supply for its customers through the use of default service contracts, which fix the price of electricity purchased for customers for periods of time ranging from three months to three years and are accounted for as normal.

PSNH mitigates the risks associated with the volatility of energy prices in procuring energy supply for its customers through its generation facilities and the use of derivative contracts, including energy forward contracts, options and FTRs. PSNH enters into these contracts in order to stabilize electricity prices for customers. Management believes any costs or benefits from these contracts are recoverable from or will be refunded to PSNH's customers, and, therefore any changes in fair value are recorded as Regulatory assets and Regulatory liabilities on the accompanying unaudited condensed consolidated balance sheets.

Yankee Gas mitigates the risks associated with supply availability and volatility of natural gas prices through the use of storage facilities and long-term agreements to purchase natural gas supply for customers that include nonderivative contracts and contracts that are accounted for as normal. Yankee Gas enters into these contracts to meet required demand levels throughout the heating season. Yankee Gas also manages supply risk through the use of options contracts. Management believes any costs or benefits from these contracts are recoverable from or refundable to Yankee Gas' customers, and, therefore, any changes in fair value are recorded as Regulatory assets and Regulatory liabilities on the accompanying unaudited condensed consolidated balance sheets.

NU Enterprises, through Select Energy, has one remaining fixed price forward sales contract that is part of its wholesale energy marketing portfolio. NU Enterprises mitigates the price risk associated with this contract through the use of forward purchase contracts. NU Enterprises' derivative contracts are accounted for at fair value, and changes in their fair values are recorded in Operating expenses on the accompanying unaudited condensed consolidated statements of income.

NU is also exposed to interest rate risk associated with its long-term debt. From time to time, various subsidiaries of the Company enter into forward starting interest rate swaps, accounted for as cash flow hedges, to mitigate the risk of changes in interest rates when they expect to issue long-term debt. NU parent has also entered into an interest rate swap on fixed rate long-term debt in order to manage the balance of fixed and floating rate debt. This interest rate swap mitigates the interest rate risk associated with the fixed rate long-term debt and is accounted for as a fair value hedge.

The gross fair values of derivative assets and liabilities with the same counterparty are offset and reported as net Derivative assets or Derivative liabilities, with appropriate current and long-term portions, in the accompanying unaudited condensed consolidated balance sheets. The following tables present the gross fair values of contracts and the net amounts recorded as current or long-term derivative assets or liabilities, by primary underlying risk exposures or purpose:


	As of March 31, 2010
	Derivatives Not Designated as Hedges
(Millions of Dollars)	Commodity and Capacity Contracts Required by Regulation		Commodity Sales Contract and Related Price and Supply Risk Management		Other Commodity Price and Supply Risk Management		Hedging Instruments-Interest Rate Risk Management		Collateral and Netting		Net Amount Recorded as Derivative Asset/(Liability)
Current Derivative Assets:
Level 2:
NU Parent	$	-	$	-	$	-	$	5.0	$	-	$	5.0
Level 3:
NU Enterprises		-		4.3		-		-		-		4.3
CL&P		5.3		-		2.8		-		-		8.1
Total Current Derivative Assets	$	5.3	$	4.3	$	2.8	$	5.0	$	-	$	17.4

Long-Term Derivative Assets:
Level 2:
NU Parent	$	-	$	-	$	-	$	9.4	$	-	$	9.4
Level 3:
NU Enterprises		-		6.5		-		-		-		6.5
CL&P ⁽¹⁾		213.7		-		-		-		(75.9)		137.8
Total Long-Term Derivative Assets	$	213.7	$	6.5	$	-	$	9.4	$	(75.9)	$	153.7

Current Derivative Liabilities:
Level 2:
PSNH	$	-	$	-	$	(25.5)	$	-	$	-	$	(25.5)
Level 3:
NU Enterprises ⁽²⁾		-		(14.3)		-		-		9.5		(4.8)
CL&P		(13.1)		-		(0.4)		-		-		(13.5)
Yankee Gas		-		-		(0.4)		-		-		(0.4)
Total Current Derivative Liabilities	$	(13.1)	$	(14.3)	$	(26.3)	$	-	$	9.5	$	(44.2)

Long-Term Derivative Liabilities:
Level 2:
PSNH	$	-	$	-	$	(9.7)	$	-	$	-	$	(9.7)
Level 3:
NU Enterprises ⁽¹⁾		-		(39.5)		-		-		0.6		(38.9)
CL&P		(923.0)		-		-		-		-		(923.0)
Yankee Gas		-		-		(0.4)		-		-		(0.4)
Total Long-Term Derivative Liabilities	$	(923.0)	$	(39.5)	$	(10.1)	$	-	$	0.6	$	(972.0)


	As of December 31, 2009
	Derivatives Not Designated as Hedges
(Millions of Dollars)	Commodity and Capacity Contracts Required by Regulation		Commodity Sales Contract and Related Price and Supply Risk Management		Other Commodity Price and Supply Risk Management		Hedging Instruments-Interest Rate Risk Management		Collateral and Netting		Net Amount Recorded as Derivative Asset/(Liability)
Current Derivative Assets:
Level 2:
NU Parent	$	-	$	-	$	-	$	6.7	$	-	$	6.7
Level 3:
CL&P		20.1		-		4.5		-		-		24.6
PSNH ⁽³⁾		-		-		0.4		-		-		0.4
Yankee Gas		-		-		0.1		-		-		0.1
Total Current Derivative Assets	$	20.1	$	-	$	5.0	$	6.7	$	-	$	31.8

Long-Term Derivative Assets:
Level 2:
NU Parent	$	-	$	-	$	-	$	6.5	$	-	$	6.5
Level 3:
CL&P ⁽¹⁾		259.0		-		-		-		(75.8)		183.2
Total Long-Term Derivative Assets	$	259.0	$	-	$	-	$	6.5	$	(75.8)	$	189.7

Current Derivative Liabilities:
Level 2:
PSNH	$	-	$	-	$	(18.8)	$	-	$	-	$	(18.8)
Level 3:
NU Enterprises ⁽²⁾		-		(13.0)		-		-		4.3		(8.7)
CL&P ⁽⁴⁾		(10.3)		-		-		-		0.5		(9.8)
Yankee Gas		-		-		(0.4)		-		-		(0.4)
Total Current Derivative Liabilities	$	(10.3)	$	(13.0)	$	(19.2)	$	-	$	4.8	$	(37.7)

Long-Term Derivative Liabilities:
Level 2:
PSNH	$	-	$	-	$	(7.6)	$	-	$	-	$	(7.6)
Level 3:
NU Enterprises⁽¹⁾		-		(41.1)		-		-		6.7		(34.4)
CL&P		(913.3)		-		-		-		-		(913.3)
Yankee Gas		-		-		(0.3)		-		-		(0.3)
Total Long-Term Derivative Liabilities	$	(913.3)	$	(41.1)	$	(7.9)	$	-	$	6.7	$	(955.6)

⁽¹⁾

Amounts in Collateral and Netting represent derivative contracts that are netted against the fair value of the gross derivative asset/liability.

⁽²⁾

Collateral and Netting amounts as of March 31, 2010 for NU Enterprises current liabilities represent cash collateral posted that is under master netting agreements. As of December 31, 2009, Collateral and Netting included derivative assets of $2.2 million that are netted against the fair value of derivative liabilities and cash collateral of $2.1 million posted under master netting agreements.

⁽³⁾

On PSNH's accompanying unaudited condensed consolidated balance sheet, the current portion of the net derivative asset is shown in Prepayments and other current assets.

⁽⁴⁾

Collateral and Netting amounts represent cash posted under master netting agreements.

For further information on the fair value of derivative contracts, see Note 1B, "Summary of Significant Accounting Policies - Fair Value Measurements," to the unaudited condensed consolidated financial statements.

The following provides additional information about the derivatives included in the tables above, including volumes and cash flow information.

Derivatives not designated as hedges

NU Enterprises' commodity sales contract and related price and supply risk management: As of March 31, 2010 and December 31, 2009, NU Enterprises had approximately 0.4 million MWh of supply volumes remaining in its wholesale portfolio when expected sales to an agency that is comprised of municipalities are compared with contracted supply, both of which extend through 2013.

CL&P commodity and capacity contracts required by regulation: As of March 31, 2010 and December 31, 2009, CL&P had contracts with two IPPs to purchase electricity monthly in amounts aggregating approximately 1.5 million MWh per year through March 2015 under one of these contracts and 0.1 million MWh per year through December 2020 under the second contract. CL&P also has two capacity-related CfDs to increase energy supply in Connecticut relating to one generating project that has been modified and one generating plant to be built. The total capacity of these CfDs and two additional CfDs entered into by UI is expected to be approximately 787 MW. CL&P has an agreement with UI, which is also accounted for as a derivative, under which they will share the

costs and benefits of the four CfDs, with 80 percent allocated to CL&P and 20 percent to UI. The four CfDs obligate the utilities to pay/receive monthly the difference between a set capacity price and the forward capacity market price that the projects receive in the ISO-NE capacity markets for periods of up to 15 years beginning in 2009.

CL&P, PSNH, and Yankee Gas energy and natural gas price and supply risk management: As of March 31, 2010 and December 31, 2009, CL&P had 2 million and 2.7 million MWh, respectively, remaining under FTRs that extend through December 2010 and require monthly payments or receipts.

PSNH has electricity procurement contracts with delivery dates through 2011 to purchase an aggregate amount of 0.9 million and 1 million MWh of power as of March 31, 2010 and December 31, 2009, respectively, that is used to serve customer load and manage price risk of its electricity delivery service obligations. These contracts are settled monthly. PSNH also has two energy call options that it received in exchange for assigning its transmission rights in a direct current transmission line. The options give PSNH the right to purchase 0.4 million and 0.6 million MWh of electricity through December 2010 as of March 31, 2010 and December 31, 2009, respectively. In addition, PSNH has entered into FTRs to manage the risk of congestion costs associated with its electricity delivery service. As of March 31, 2010 and December 31, 2009, there were 0.1 million and 0.4 million MWh, respectively, remaining under FTRs that extend through December 2010 and required monthly payments or receipts. The purpose of the PSNH derivative contracts is to provide stable rates for customers by mitigating price uncertainties associated with the New England electricity spot market.

As of March 31, 2010 and December 31, 2009, Yankee Gas had two peaking supply option contracts to purchase up to 17 thousand MMBtu of natural gas on up to 20 days per season to manage natural gas supply price risk related to winter load obligations. One contract for three thousand MMBtu expires on October 31, 2010 and the other contract for 14 thousand MMBtu expires on April 1, 2012. Demand fees on these contracts are paid annually and are included in Yankee Gas' PGA clause for recovery.

The following table presents the realized and unrealized gains/(losses) associated with derivative contracts not designated as hedges:


		Amount of Gain/(Loss) Recognized on Derivative Instrument
Derivatives Not Designated as Hedges	Location of Gain or Loss Recognized on Derivative	For the Three Months Ended March 31, 2010		For the Three Months Ended March 31, 2009
NU Enterprises:		(Millions of Dollars)		(Millions of Dollars)
Commodity sales contract and related price and supply risk management	Fuel, purchased and net interchange power	$	(0.2)	$	5.5
Regulated Companies:
CL&P energy and capacity contracts required by regulation	Regulatory assets/liabilities		(68.7)		(11.1)
Other Commodity price and supply risk management:
CL&P	Regulatory assets/liabilities		(3.0)		(5.9)
PSNH	Regulatory assets/liabilities		(17.6)		(42.5)
Yankee Gas	Regulatory assets/liabilities		(0.4)		(0.9)

For the Regulated companies, monthly settlement amounts are recorded as receivables or payables and as Operating revenues or Fuel, purchased and net interchange power on the accompanying unaudited condensed consolidated financial statements. Regulatory assets/liabilities are established with no impact to Net income.

Derivatives designated as hedging instruments

Interest Rate Risk Management: To manage the interest rate risk characteristics of NU parent's fixed rate long-term debt, NU parent has a fixed to floating interest rate swap on its $263 million, 7.25 percent fixed rate senior notes maturing on April 1, 2012. This interest rate swap qualifies and was designated as a fair value hedge and requires semi-annual cash settlements. The changes in fair value of the swap and the interest component of the hedged long-term debt instrument are recorded in Interest expense on the accompanying unaudited condensed consolidated statements of income. There was no ineffectiveness recorded for the three months ended March 31, 2010 and 2009. The cumulative changes in fair values of the swap and the Long-term debt are recorded as a Derivative asset/liability and an adjustment to Long-term debt. Interest receivable is recorded as a reduction of Interest expense and is included in Prepayments and other current assets.

For the three months ended March 31, 2010 and 2009, the realized and unrealized gains/(losses) related to changes in fair value of the swap and Long-term debt as well as pre-tax Interest expense, recorded in Net income, were as follows:


	For the Three Months Ended March 31, 2010				For the Three Months Ended March 31, 2009
(Millions of Dollars)	Swap		Hedged Debt		Swap		Hedged Debt
Changes in fair value	$	3.9	$	(3.9)	$	0.5	$	(0.5)
Interest recorded in Net income		-		2.8		-		1.4

There were no cash flow hedges outstanding as of or during the three months ended March 31, 2010 and 2009 and no ineffectiveness was recorded during these periods. From time to time, NU, including CL&P, PSNH and WMECO, enters into forward starting interest rate swap agreements on proposed debt issuances that qualify and are designated as cash flow hedges. Cash flow hedges are recorded at fair value, and the changes in the fair value of the effective portion of those contracts are recognized in Accumulated other comprehensive loss. Cash flow hedges impact Net income when hedge ineffectiveness is measured and recorded, when the forecasted transaction being hedged is improbable of occurring or when the transaction is settled. When a cash flow hedge is terminated, the settlement amount is recorded in Accumulated other comprehensive loss and is amortized into Net income over the term of the underlying debt instrument.

Pre-tax gains/(losses) amortized from Accumulated other comprehensive loss into Interest expense on the accompanying unaudited condensed consolidated statements of income were as follows:


(Millions of Dollars)	For the Three Months Ended March 31, 2010		For the Three Months Ended March 31, 2009
CL&P	$	(0.2)	$	(0.2)
Other		0.1		0.1
NU	$	(0.1)	$	(0.1)

For further information, see Note 5, "Comprehensive Income," to the unaudited condensed consolidated financial statements.

Credit Risk

Certain derivative contracts that are accounted for at fair value, including PSNH's electricity procurement contracts, CL&P's bilateral agreements and NU Enterprises' electricity sourcing contracts, contain credit risk contingent features. These features require these companies or, in NU Enterprises' case, NU parent, to maintain investment grade credit ratings from the major rating agencies and to post cash or standby LOCs as collateral for contracts in a net liability position over specified credit limits. NU parent provides standby LOCs under its revolving credit agreement for NU subsidiaries to post with counterparties. The following summarizes the fair value of derivative contracts that are in a liability position and subject to credit risk contingent features and the fair value of cash collateral and standby LOCs posted with counterparties as of March 31, 2010 and December 31, 2009:


	As of March 31, 2010
(Millions of Dollars)	Fair Value Subject to Credit Risk Contingent Features		Cash Collateral Posted		Standby LOCs Posted
PSNH	$	(35.2)	$	-	$	34.0
NU Enterprises		(26.1)		9.5		-
NU	$	(61.3)	$	9.5	$	34.0


	As of December 31, 2009
(Millions of Dollars)	Fair Value Subject to Credit Risk Contingent Features		Cash Collateral Posted		Standby LOCs Posted
PSNH	$	(26.4)	$	-	$	25.0
NU Enterprises		(20.0)		2.1		-
NU	$	(46.4)	$	2.1	$	25.0

Additional collateral is required to be posted by NU Enterprises, CL&P or PSNH, respectively, if NU parent's, CL&P's or PSNH's respective unsecured debt credit ratings are downgraded below investment grade. As of March 31, 2010, no additional cash collateral would have been required to be posted if credit ratings had been downgraded below investment grade. However, if PSNH's or NU parent's senior unsecured debt had been downgraded to below investment grade, additional standby LOCs in the amount of $6.5 million and $17 million would have been required to be posted on derivative contracts for PSNH and Select Energy, respectively. As of December 31, 2009, no additional cash collateral would have been required to be posted if credit ratings had been downgraded below investment grade. However, if PSNH's or NU parent's senior unsecured debt had been downgraded to below investment grade, additional standby LOCs in the amount of $1.8 million and $17.8 million would have been required to be posted on derivative contracts for PSNH and Select Energy, respectively.

For further information, see Note 1H, "Summary of Significant Accounting Policies - Special Deposits and Counterparty Deposits," to the unaudited condensed consolidated financial statements.

Fair Value Measurements of Derivative Instruments:

Valuation of Derivative Instruments: Derivative contracts classified as Level 2 in the fair value hierarchy include Other Commodity Price and Supply Risk Management Contracts and Interest Rate Risk Management Contracts. Other Commodity Price and Supply Risk Management Contracts include PSNH forward contracts to purchase energy for periods for which prices are quoted in an active market. Prices are obtained from broker quotes and based on actual market activity. The contracts are valued using the mid-point of the bid-ask spread. Valuations of these contracts also incorporate discount rates using the yield curve approach. Interest Rate Risk

Management contracts represent interest rate swap agreements and are valued using a market approach provided by the swap counterparty using a discounted cash flow approach utilizing forward interest rate curves.

The derivative contracts classified as Level 3 in the tables below include NU Enterprise's Sales Contract and Related Price and Supply Risk Management contracts, the Regulated companies’ Commodity and Capacity Contracts Required by Regulation (including CL&P's CfDs and contracts with certain IPPs), and Other Commodity Price and Supply Risk Management contracts (PSNH and Yankee Gas physical options, and CL&P and PSNH FTRs.) For Commodity and Capacity Contracts Required by Regulation and NU Enterprises’ Commodity Sales contract, fair value is modeled using income techniques such as discounted cash flow approaches adjusted for assumptions relating to exit price. Significant observable inputs for valuations of these contracts include energy and energy-related product prices for which quoted prices in an active market exist. Significant unobservable inputs used in the valuations of these contracts include energy and energy-related product prices for future years for long-dated derivative contracts and future contract quantities under requirements and supplemental sales contracts. Discounted cash flow valuations incorporate estimates of premiums or discounts that would be required by a market participant to arrive at an exit price, using available historical market transaction information. Valuations of derivative contracts include assumptions regarding the timing and likelihood of scheduled payments and also reflect nonperformance risk, including credit, using the default probability approach based on the counterparty's credit rating for assets and the company’s credit rating for liabilities.

Other Commodity Price and Supply Risk Management contracts classified as Level 3 in the tables below are valued using income approaches including a Black-Scholes option pricing model. Observable inputs used in valuing options include prices for energy and energy-related products for years for which quoted prices in an active market exist. Unobservable inputs included in the valuation of options contracts include market volatilities related to future energy prices and the estimated likelihood that the option will be exercised. FTRs are valued using broker quotes based on prices in an inactive market.

Valuations using significant unobservable inputs: The following tables present changes for the three months ended March 31, 2010 and 2009 in the Level 3 category of derivative assets and derivative liabilities measured at fair value on a recurring basis. The derivative assets and liabilities are presented on a net basis. The Company classifies assets and liabilities in Level 3 of the fair value hierarchy when there is reliance on at least one significant unobservable input to the valuation model. In addition to these unobservable inputs, the valuation models for Level 3 assets and liabilities typically also rely on a number of inputs that are observable either directly or indirectly. Thus the gains and losses presented below include changes in fair value that are attributable to both observable and unobservable inputs. There were no transfers into or out of Level 3 assets and liabilities for the three months ended March 31, 2010 or 2009:


	For the Three Months Ended March 31, 2010
	NU
(Millions of Dollars)	Commodity and Capacity Contracts Required By Regulation		Commodity Sales Contracts and Related Price and Supply Risk Management		Other Commodity Price and Supply Risk Management		Total Level 3
Derivatives, Net:
Fair value at beginning of period	$	(720.3)	$	(45.2)	$	4.3	$	(761.2)
Net realized/unrealized losses included in:
Net income ⁽¹⁾		-		(0.2)		-		(0.2)
Regulatory assets/liabilities		(68.7)		-		(3.6)		(72.3)
Purchases, issuances and settlements		(3.9)		2.8		0.9		(0.2)
Fair value at end of period	$	(792.9)	$	(42.6)	$	1.6	$	(833.9)
Period change in unrealized losses included in Net income relating to items held at end of period	$	-	$	(0.6)	$	-	$	(0.6)


	For the Three Months Ended March 31, 2010
	CL&P						PSNH
(Millions of Dollars)	Commodity and Capacity Contracts Required By Regulation		Other Commodity Price and Supply Risk Management		Total Level 3		Other Commodity Price and Supply Risk Management
Derivatives, Net:
Fair value at beginning of period	$	(720.3)	$	4.5	$	(715.8)	$	0.4
Net realized/unrealized losses included in:
Regulatory assets/liabilities		(68.7)		(3.0)		(71.7)		(0.2)
Purchases, issuances and settlements		(3.9)		0.9		(3.0)		(0.2)
Fair value at end of period	$	(792.9)	$	2.4	$	(790.5)	$	-


	For the Three Months Ended March 31, 2009
(Millions of Dollars)	NU		CL&P		PSNH
Derivatives, Net:
Fair value at beginning of period	$	(669.2)	$	(611.1)	$	4.1
Net realized/unrealized gains/(losses) included in:
Net income ⁽¹⁾		5.5		-		-
Regulatory assets/liabilities		(20.6)		(17.0)		(2.7)
Purchases, issuances and settlements		4.0		(5.2)		-
Fair value at end of period	$	(680.3)	$	(633.3)	$	1.4
Period change in unrealized gains included in Net income relating to items held at end of period	$	5.3	$	-	$	-

⁽¹⁾

Realized and unrealized gains and losses on derivatives included in Net Income relate to the remaining NU Enterprises' marketing contracts and are reported in Fuel, purchased and net interchange power on the accompanying unaudited condensed consolidated statements of income.

PENSION BENEFITS AND POSTRETIREMENT BENEFITS OTHER THAN PENSIONS

NUSCO, a subsidiary of NU, sponsors the Pension Plan, a single uniform noncontributory defined benefit retirement plan, which is subject to the provisions of the Employee Retirement Income Security Act. The Pension Plan covers nonbargaining unit employees (and bargaining unit employees, as negotiated) of NU, including CL&P, PSNH, and WMECO, hired before 2006 (or as negotiated, for bargaining unit employees). On behalf of NU's retirees, NUSCO also sponsors plans that provide certain retiree health care benefits, primarily medical and dental, and life insurance benefits through a PBOP Plan. In addition, NU maintains a SERP, which provides benefits to eligible participants who are officers of NU. This plan primarily provides benefits that would have been provided to these employees under the Pension Plan if certain Internal Revenue Code limitations were not imposed.

The components of net periodic expense/(income) for the Pension Plan, PBOP Plan and SERP for the three months ended March 31, 2010 and 2009 are as follows:


	For the Three Months Ended March 31,
NU	Pension Benefits				PBOP Benefits				SERP Benefits
(Millions of Dollars)	2010		2009		2010		2009		2010		2009
Service cost	$	13.0	$	11.3	$	2.2	$	1.8	$	0.2	$	0.2
Interest cost		37.4		38.5		6.7		7.3		0.6		0.6
Expected return on plan assets		(45.6)		(47.4)		(5.4)		(5.1)		-		-
Net transition obligation cost		-		0.1		2.9		2.9		-		-
Prior service cost/(credit)		2.5		2.5		(0.1)		(0.1)		-		-
Actuarial loss		12.6		5.1		4.0		2.5		0.2		0.1
Total - net periodic expense	$	19.9	$	10.1	$	10.3	$	9.3	$	1.0	$	0.9

CL&P - net periodic expense/(income)	$	2.0	$	(1.4)	$	4.2	$	4.0	$	0.1	$	0.1
PSNH - net periodic expense	$	7.2	$	5.8	$	1.9	$	1.8	$	0.1	$	0.1
WMECO - net periodic (income)/expense	$	*	$	(0.7)	$	0.8	$	0.7	$	*	$	*

*A de minimis amount of net periodic expense was recorded for WMECO.

Not included in the Pension Plan, PBOP Plan and SERP amounts above for CL&P, PSNH and WMECO are related intercompany allocations as follows:


	For the Three Months Ended March 31,
	CL&P				PSNH				WMECO
(Millions of Dollars)	2010		2009		2010		2009		2010		2009
Pension Benefits	$	5.6	$	3.7	$	1.3	$	0.8	$	1.0	$	0.6
PBOP Benefits		1.9		1.7		0.5		0.4		0.3		0.3
SERP Benefits		0.5		0.5		0.1		0.1		0.1		0.1

A portion of the pension amounts is capitalized related to employees who are working on capital projects. Amounts capitalized, including intercompany allocations, for NU, CL&P, PSNH and WMECO were as follows:


	For the Three Months Ended March 31,
(Millions of Dollars)	2010		2009
NU	$	4.4	$	1.5
CL&P		1.7		*
PSNH		2.0		1.4
WMECO		0.2		(0.2)

*A de minimis portion of the pension amounts was capitalized for CL&P.

The amounts for the three months ended March 31, 2009 for CL&P and WMECO offset capital costs, as pension income was recorded related to these capital projects.

COMMITMENTS AND CONTINGENCIES

Environmental Matters (HWP, PSNH)

HWP: HWP is a subsidiary of NU that remains in the process of evaluating additional potential remediation requirements at a river site in Massachusetts containing tar deposits associated with a MGP site which it sold to HG&E, a municipal electric utility, in 1902. MGP sites are sites where the process of producing manufactured gas from coal created certain byproducts that may pose a risk to human health and the environment. HWP is at least partially responsible for this site, and has already conducted substantial investigative and remediation activities. HWP first established a reserve for this site in 1994.

The MA DEP issued a letter in 2008 to HWP and HG&E, which share responsibility for the site, providing conditional authorization for additional investigatory and risk characterization activities and providing detailed comments on HWP's 2007 reports and proposals for further investigations. The MA DEP also indicated that further removal of tar in certain areas was necessary. This letter represented guidance rather than a mandate from the MA DEP. HWP developed and implemented site characterization studies to further delineate tar deposits in conformity with the MA DEP's guidance letter. On April 5, 2010, HWP delivered a report to the MA DEP describing the results to date of its site investigation studies and testing. These matters are subject to ongoing discussions with the MA DEP and HG&E and are subject to change in the future.

Pre-tax charges of $1.1 million and $3 million were recorded in 2009 and 2008, respectively, to reflect the estimated costs of tar delineation and site characterization studies. For the three months ended March 31, 2010, a pre-tax charge of $1 million was recorded to reflect the estimated remaining costs to complete these studies and analyze and substantiate them for the MA DEP. The cumulative expense recorded to the reserve for this environmental matter through March 31, 2010 was approximately $17.9 million, of which $16.3 million had been spent, leaving approximately $1.6 million in the reserve as of March 31, 2010, representing estimated costs for HWP to substantiate its studies and conduct certain soft tar remediation. At this time, management believes that the $1.6 million remaining in the reserve is at the low end of a range of probable costs for HWP and additional costs cannot be reasonably estimated at this time.

There are many outcomes that could affect management's estimates and require an increase to the reserve, which would be reflected as a charge to pre-tax Net income. However, management cannot reasonably estimate potential additional investigation or remediation costs because they will depend on, among other things, the nature, extent and timing of additional investigation and remediation that may be required by the MA DEP and could be material to the financial statements, although management does not believe that a material increase to the reserve is probable. HWP's share of the costs related to this site is not recoverable from customers.

PSNH: MGP sites comprise the largest portion of PSNH's environmental liabilities. PSNH has conducted substantial investigative activities and evaluated remediation requirements in the Ashuelot River and Mill Creek in Keene, New Hampshire, which contains coal tar deposits.

For the three months ended March 31, 2010, a deferral of $7.5 million was recorded to reflect estimated remediation activities approved by the New Hampshire Department of Environmental Services and expected to be performed in 2010 and 2011. The cumulative expense recorded to the reserve for this environmental matter through March 31, 2010 was approximately $13.6 million, of which $6 million had been spent, leaving approximately $7.6 million in the reserve as of March 31, 2010. The $7.6 million remaining in the reserve is management's best estimate to complete the remediation activities.

The $7.5 million deferral was recorded in Other long-term liabilities with an offset recorded to Regulatory assets on the accompanying unaudited condensed consolidated balance sheet because PSNH has a regulatory rate recovery mechanism for environmental costs. Management believes these costs are probable of recovery in future cost-of-service regulated rates.

Guarantees and Indemnifications

NU parent provides credit assurances on behalf of its subsidiaries, including CL&P, PSNH and WMECO, in the form of guarantees and LOCs in the normal course of business. NU has also provided guarantees and various indemnifications on behalf of external parties as a result of the sale of SESI, formerly a subsidiary of NU Enterprises. The aggregate fair value amount recorded for these guarantees and indemnifications since the sale of SESI totaled $0.3 million. Other indemnifications in connection with the sale of SESI include the completeness and accuracy of information provided, compliance with laws, and various claims, specific indemnifications for estimated costs to complete or modify specific projects, indemnifications to lenders for payment of shortfalls in the event of early termination of government contracts, and surety bonds covering certain projects. The maximum exposure on these items is either not specified or not material, and no amounts are recorded as liabilities.

In addition, NU parent provided guarantees and various indemnifications on behalf of external parties as a result of the sales of NU Enterprises' former retail marketing business and competitive generation business. These included indemnifications for compliance with tax and environmental laws, and various claims for which the maximum exposure was not specified in the sale agreements.

Management does not anticipate a material impact to net income to result from these various guarantees and indemnifications. The following table summarizes the NU, including CL&P, PSNH, and WMECO, maximum exposure as of March 31, 2010, in accordance with guidance on guarantor's accounting and disclosure requirements for guarantees and expiration dates:


Company	Description	Maximum Exposure (in millions)		Expiration Date(s)
Subsidiary:

Various	Surety bonds	$13.4		July 2010 - June 2011 (1)

PSNH and Select Energy	Letters of credit	$49.6		June - November 2010

RRR and NUSCO	Lease payments for real estate and vehicles	$11.6		Through 2024

Boulos	Surety bonds covering ongoing projects	$26.2		Through project completion

NGS	Performance guarantee and insurance bonds	$18.6	(2)	(2)

Select Energy	Performance guarantees for wholesale contracts	$74.5	(3)	2013

(1)

Surety bond expiration dates reflect bond termination dates, the majority of which will be renewed or extended.

(2)

Included in the maximum exposure is $17.5 million related to a performance guarantee of NGS obligations for which no maximum exposure is specified in the agreement. The maximum exposure was calculated as of March 31, 2010 based on limits of NGS's liability contained in the underlying service contract and assumes that NGS will perform under that contract through its expiration in 2020. The remaining $1.1 million of maximum exposure relates to insurance bonds with no expiration date that are billed annually on their anniversary date.

(3)

Maximum exposure is as of March 31, 2010, assuming purchase contracts guaranteed have no value; however, actual exposures vary with underlying commodity prices.

CL&P, PSNH and WMECO have no guarantees of the performance of third parties.

Many of the underlying contracts that NU parent guarantees, as well as certain surety bonds, contain credit ratings triggers that would require NU parent to post collateral in the event that NU's unsecured debt credit ratings are downgraded below investment grade.

COMPREHENSIVE INCOME

Total comprehensive income, which includes all comprehensive income/(loss) items, net of tax and by category, for the three months ended March 31, 2010 and 2009 is as follows:


	Three Months Ended March 31,
	2010		2009
(Millions of Dollars)	NU		NU
Net income	$	87.6	$	99.1
Other comprehensive income items, net of tax:
Qualified cash flow hedging instruments ⁽¹⁾		-		-
Changes in unrealized gains on other securities ⁽²⁾		0.2		-
Change in pension, SERP and PBOP benefit plans		0.5		0.2
Other comprehensive income items		0.7		0.2
Total comprehensive income		88.3		99.3
Comprehensive income attributable to noncontrolling interest		1.4		1.4
Comprehensive income attributable to controlling interest	$	86.9	$	97.9


	Three Months Ended March 31, 2010						Three Months Ended March 31, 2009
(Millions of Dollars)	CL&P		PSNH		WMECO		CL&P		PSNH		WMECO
Net income	$	48.4	$	15.8	$	5.7	$	53.1	$	17.5	$	6.1
Other comprehensive income items, net of tax:
Qualified cash flow hedging instruments ⁽¹⁾		0.1		-		-		0.1		-		-
Other comprehensive income items		0.1		-		-		0.1		-		-
Total comprehensive income	$	48.5	$	15.8	$	5.7	$	53.2	$	17.5	$	6.1

⁽¹⁾

Hedged transactions impacting Net income in the tables above represent amounts that were reclassified from Accumulated other comprehensive loss into Net income in connection with the settlement of interest rate swap agreements and the amortization of the effects of interest rate hedges. As of March 31, 2010, the balance included in Accumulated other comprehensive loss related to hedging activities was $4.4 million, $3.1 million, $0.7 million, and a de minimis amount for NU, CL&P, PSNH and WMECO, respectively. These amounts were $4.4 million, $3.2 million, $0.7 million, and a de minimis amount as of December 31, 2009 for NU, CL&P, PSNH and WMECO, respectively.

⁽²⁾

Represents changes in unrealized gains/(losses) on securities held in the NU supplemental benefit trust. For further information, see Note 9, "Marketable Securities," to the unaudited condensed consolidated financial statements.

There were no forward starting interest rate swaps entered into for the three months ended March 31, 2010 or March 31, 2009. For NU, it is estimated that a charge of $0.2 million will be reclassified from Accumulated other comprehensive loss as a decrease to Net income over the next 12 months as a result of amortization of interest rate swap agreements, which have been settled. Included in this amount are estimated charges of $0.4 million and $0.1 million for CL&P and PSNH, respectively, and a benefit of $0.1 million for WMECO. As of March 31, 2010, it is estimated that a pre-tax amount of $0.7 million included in the Accumulated other comprehensive loss balance will be reclassified as a decrease to Net income over the next 12 months related to Pension Plan, SERP and PBOP Plan benefits adjustments for NU.

EARNINGS PER SHARE (NU)

EPS is computed based upon the monthly weighted average number of common shares outstanding, excluding unallocated ESOP shares, during each period. Diluted EPS is computed on the basis of the monthly weighted average number of common shares outstanding plus the potential dilutive effect if certain securities are converted into common shares. The computation of diluted EPS excludes the effect of the potential exercise of share awards when the average market price of the common shares is lower than the exercise price of the related awards during the period. These outstanding share awards are not included in the computation of diluted EPS because the effect would have been antidilutive. For the three month period ended March 31, 2010, there were 6,311 share awards excluded from the computation as these awards were antidilutive. There were no antidilutive share awards outstanding for the three month period ended March 31, 2009.

The following table sets forth the components of basic and fully diluted EPS:


	For the Three Months Ended March 31,
(Millions of Dollars, except for share information)	2010		2009
Net income attributable to controlling interest	$	86.2	$	97.7
Basic weighted average common shares outstanding		176,349,762		162,340,475
Dilutive effect		187,710		584,692
Fully diluted weighted average common shares outstanding		176,537,472		162,925,167
Basic and fully diluted EPS	$	0.49	$	0.60

RSUs and performance shares are included in basic common shares outstanding as of the date that all necessary vesting conditions have been satisfied. The dilutive effect of outstanding RSUs and performance shares for which common shares have not been issued

is calculated using the treasury stock method. Assumed proceeds of the units under the treasury stock method consist of the remaining compensation cost to be recognized and a theoretical tax benefit. The theoretical tax benefit is calculated as the tax impact of the intrinsic value of the units (the difference between the market value of the units, using the average market price during the period, and the grant date market value).

The dilutive effect of stock options is also calculated using the treasury stock method. Assumed proceeds for stock options consist of remaining compensation cost to be recognized, cash proceeds that would be received upon exercise, and a theoretical tax benefit. The theoretical tax benefit is calculated as the tax impact of the intrinsic value of the stock options (the difference between the market value of the average stock options outstanding for the period, using the average market price during the period, and the grant price).

Allocated ESOP shares are included in basic common shares outstanding in the above table.

LONG-TERM DEBT (WMECO)

On March 8, 2010, WMECO issued $95 million of Series E senior unsecured notes with a coupon rate of 5.1 percent and a maturity date of March 1, 2020. The proceeds of these notes were used to repay short-term borrowings incurred in the ordinary course of business and to fund WMECO’s ongoing capital investment programs.

The indenture under which the notes were issued requires WMECO to comply with certain covenants as are customarily included in such indentures. WMECO was in compliance with these covenants as of March 31, 2010.

FAIR VALUE OF FINANCIAL INSTRUMENTS

The following methods and assumptions were used to estimate the fair value of each of the following financial instruments:

Preferred Stock, Long-Term Debt and Rate Reduction Bonds: The fair value of CL&P's preferred stock is based upon pricing models that incorporate interest rates and other market factors, valuations or trades of similar securities and cash flow projections. The fair value of fixed-rate long-term debt securities and RRBs is based upon pricing models that incorporate quoted market prices for those issues or similar issues adjusted for market conditions, credit ratings of the respective companies and treasury benchmark yields. Adjustable rate securities are assumed to have a fair value equal to their carrying value. Carrying amounts and estimated fair values are as follows:


	As of March 31, 2010				As of December 31, 2009
	NU				NU
(Millions of Dollars)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Preferred stock not subject to mandatory redemption	$	116.2	$	93.1	$	116.2	$	86.8
Long-term debt -
First mortgage bonds		2,657.7		2,844.2		2,657.7		2,713.5
Other long-term debt		1,988.7		2,047.4		1,893.6		1,938.0
Rate reduction bonds		375.9		416.9		442.4		487.3


		As of March 31, 2010
		CL&P				PSNH					WMECO
(Millions of Dollars)		Carrying Amount		Fair Value		Carrying Amount			Fair Value		Carrying Amount		Fair Value
Preferred stock not subject to mandatory redemption	$		116.2	$	93.1		$	-	$	-	$	-	$	-
Long-term debt -
First mortgage bonds			1,919.8		2,066.2			430.0		448.4		-		-
Other long-term debt			667.5		671.4			407.3		409.8		400.9		414.2
Rate reduction bonds			144.9		166.5			176.2		190.8		54.8		59.6


		As of December 31, 2009
		CL&P				PSNH					WMECO
(Millions of Dollars)		Carrying Amount		Fair Value		Carrying Amount			Fair Value		Carrying Amount		Fair Value
Preferred stock not subject to mandatory redemption	$		116.2	$	86.8		$	-	$	-	$	-	$	-
Long-term debt -
First mortgage bonds			1,919.8		1,960.6			430.0		425.4		-		-
Other long-term debt			667.4		673.4			407.3		408.6		305.9		304.9
Rate reduction bonds			195.6		220.1			188.1		203.5		58.7		63.7

The NU other long-term debt includes $300.7 million and $300.6 million of fees and interest due for spent nuclear fuel disposal costs as of March 31, 2010 and December 31, 2009, respectively. CL&P's portion of this obligation is $243.6 million and $243.5 million as of March 31, 2010 and December 31, 2009, respectively. WMECO's portion of this obligation is $57.1 million as of March 31, 2010 and December 31, 2009.

Derivative Instruments: NU, including CL&P and PSNH, holds various derivative instruments that are carried at fair value. For further information, see Note 2, "Derivative Instruments," to the unaudited condensed consolidated financial statements.

Other Financial Instruments: Investments in marketable securities are carried at fair value on the accompanying unaudited condensed consolidated balance sheets. For further information, see Note 1B, "Summary of Significant Accounting Policies - Fair Value Measurements," and Note 9, "Marketable Securities," to the unaudited condensed consolidated financial statements.

NU parent holds a long-term government receivable related to SESI. The carrying value of the receivable was $8.8 million as of March 31, 2010 and is included in Other long-term assets on the accompanying unaudited condensed consolidated balance sheets. The fair value of this receivable was $10.7 million and $10.6 million as of March 31, 2010 and December 31, 2009, respectively, and was determined based on discounted cash flows using a seven-year Treasury rate to match the weighted average life of the anticipated cash flow stream.

The carrying value of other financial instruments included in current assets and current liabilities, including cash and cash equivalents and special deposits, approximates their fair value due to the short-term nature of these instruments.

MARKETABLE SECURITIES (NU, WMECO)

The Company elected to record exchange traded mutual funds purchased during 2009 in the NU supplemental benefit trust at fair value in order to reflect the economic effect of changes in fair value of all newly purchased equity securities in Net income. These equity securities, classified as Level 1 in the fair value hierarchy, totaled $37 million and $35.3 million as of March 31, 2010 and December 31, 2009, respectively. Net gains on these securities of $1.7 million for the three months ended March 31, 2010 were recorded in Other income, net on the accompanying unaudited condensed consolidated statement of income. Dividend income is recorded when dividends are declared and are recorded in Other income, net on the accompanying unaudited condensed consolidated statements of income. All other marketable securities are accounted for as available-for-sale.

Available-for-Sale Securities: The following is a summary by security type of NU's available-for-sale securities held in the NU supplemental benefit trust and WMECO's spent nuclear fuel trust. These securities are recorded at fair value and included in current and long-term portions of marketable securities on the accompanying unaudited condensed consolidated balance sheets.


	As of March 31, 2010
(Millions of Dollars)	Amortized Cost		Pre-Tax Gross Unrealized Gains ⁽¹⁾		Pre-Tax Gross Unrealized Losses ⁽¹⁾		Fair Value
NU supplemental benefit trust
U.S. government issued debt securities (agency and treasury)	$	11.2	$	0.3	$	(0.2)	$	11.3
Corporate debt securities		8.4		0.4		-		8.8
Municipal bonds		0.3		-		-		0.3
Asset backed debt securities		5.5		0.3		-		5.8
Money market funds and other		3.7		-		-		3.7
Total NU supplemental benefit trust	$	29.1	$	1.0	$	(0.2)	$	29.9


	As of March 31, 2010
(Millions of Dollars)	Amortized Cost		Pre-Tax Gross Unrealized Gains ⁽¹⁾		Pre-Tax Gross Unrealized Losses ⁽¹⁾		Fair Value
WMECO spent nuclear fuel trust
U.S. government issued debt securities (agency and treasury)	$	12.0	$	-	$	-	$	12.0
Corporate debt securities		15.5		-		(0.1)		15.4
Municipal bonds		10.5		-		-		10.5
Asset backed debt securities		0.8		-		(0.1)		0.7
Money market funds and other		18.2		-		-		18.2
Total WMECO spent nuclear fuel trust	$	57.0	$	-	$	(0.2)	$	56.8
Total NU	$	86.1	$	1.0	$	(0.4)	$	86.7


	As of December 31, 2009
(Millions of Dollars)	Amortized Cost		Pre-Tax Gross Unrealized Gains ⁽¹⁾		Pre-Tax Gross Unrealized Losses ⁽¹⁾		Fair Value
NU supplemental benefit trust
U.S. government issued debt securities (agency and treasury)	$	12.8	$	0.3	$	(0.2)	$	12.9
Corporate debt securities		7.4		0.4		(0.1)		7.7
Municipal bonds		0.2		-		-		0.2
Asset backed debt securities		5.2		0.1		(0.1)		5.2
Money market funds and other		3.0		-		-		3.0
Total NU supplemental benefit trust	$	28.6	$	0.8	$	(0.4)	$	29.0


WMECO spent nuclear fuel trust
U.S. government issued debt securities (agency and treasury)	$	17.0	$	-	$	-	$	17.0
Corporate debt securities		17.4		0.1		(0.1)		17.4
Municipal bonds		10.6		-		-		10.6
Asset backed debt securities		1.1		-		(0.2)		0.9
Money market funds and other		10.9		-		-		10.9
Total WMECO spent nuclear fuel trust	$	57.0	$	0.1	$	(0.3)	$	56.8
Total NU	$	85.6	$	0.9	$	(0.7)	$	85.8

⁽¹⁾

Unrealized gains and losses on debt securities for the NU supplemental benefit trust and WMECO spent nuclear fuel trust are recorded in Accumulated other comprehensive loss and Other long-term assets, respectively, on the accompanying unaudited condensed consolidated balance sheets. For information related to the change in unrealized gains and losses for the NU supplemental benefit trust included in Accumulated other comprehensive loss, see Note 5, "Comprehensive Income," to the unaudited condensed consolidated financial statements.

Unrealized Losses and Other-than-Temporary Impairment: Gross unrealized losses and fair values of debt securities that have been in a continuous unrealized loss position for less than 12 months and 12 months or greater are as follows:


	As of March 31, 2010
	Less than 12 Months				12 Months or Greater				Total
(Millions of Dollars)	Fair Value		Pre-Tax Gross Unrealized Losses		Fair Value		Pre-Tax Gross Unrealized Losses		Fair Value		Pre-Tax Gross Unrealized Losses
NU supplemental benefit trust
U.S. government issued debt securities (agency and treasury)	$	5.6	$	(0.2)	$	-	$	-	$	5.6	$	(0.2)
Total NU supplemental benefit trust	$	5.6	$	(0.2)	$	-	$	-	$	5.6	$	(0.2)

WMECO spent nuclear fuel trust
Corporate debt securities	$	-	$	-	$	0.2	$	(0.1)	$	0.2	$	(0.1)
Asset backed debt securities		-		-		0.4		(0.1)		0.4		(0.1)
Total WMECO spent nuclear fuel trust	$	-	$	-	$	0.6	$	(0.2)	$	0.6	$	(0.2)
Total NU	$	5.6	$	(0.2)	$	0.6	$	(0.2)	$	6.2	$	(0.4)


	As of December 31, 2009
	Less than 12 Months				12 Months or Greater				Total
(Millions of Dollars)	Fair Value		Pre-Tax Gross Unrealized Losses		Fair Value		Pre-Tax Gross Unrealized Losses		Fair Value		Pre-Tax Gross Unrealized Losses
NU supplemental benefit trust
U.S. government issued debt securities (agency and treasury)	$	6.6	$	(0.1)	$	0.7	$	(0.1)	$	7.3	$	(0.2)
Corporate debt securities		-		-		0.4		(0.1)		0.4		(0.1)
Asset backed debt securities		-		-		1.2		(0.1)		1.2		(0.1)
Total NU supplemental benefit trust	$	6.6	$	(0.1)	$	2.3	$	(0.3)	$	8.9	$	(0.4)

WMECO spent nuclear fuel trust
Corporate debt securities	$	-	$	-	$	0.2	$	(0.1)	$	0.2	$	(0.1)
Asset backed debt securities		-		-		0.5		(0.2)		0.5		(0.2)
Total WMECO spent nuclear fuel trust	$	-	$	-	$	0.7	$	(0.3)	$	0.7	$	(0.3)
Total NU	$	6.6	$	(0.1)	$	3.0	$	(0.6)	$	9.6	$	(0.7)

As of March 31, 2010 and December 31, 2009, there were no debt securities that the Company intends to sell or that management believes the Company will more likely than not be required to sell before recovery of amortized cost. Credit losses for the NU supplemental benefit trust were de minimis for the three months ended March 31, 2010 and were recorded in Other income, net on the accompanying unaudited condensed consolidated income statement. There were no credit losses for the WMECO spent nuclear fuel trust for the three months ended March 31, 2010. Inception to date credit losses were de minimis for the NU supplemental benefit trust and $0.7 million for the WMECO spent nuclear fuel trust. Factors considered in determining whether a credit loss exists include the duration and severity of the impairment, adverse conditions specifically affecting the issuer, and the payment history, ratings and rating changes of the security. For asset backed securities, underlying collateral and expected future cash flows are also evaluated. All of the corporate and asset-backed securities held in the NU supplemental benefit trust are rated above investment grade. All but two of the securities in the WMECO spent nuclear fuel trust are rated above investment grade and credit losses have been recorded for those securities that are below investment grade.

For information related to the change in unrealized gains included in Accumulated other comprehensive loss, see Note 5, "Comprehensive Income," to the unaudited condensed consolidated financial statements.

Contractual Maturities: As of March 31, 2010, the contractual maturities of available-for-sale debt securities are as follows:


		NU			WMECO
(Millions of Dollars)		Amortized Cost		Fair Value		Amortized Cost		Fair Value
Less than one year	$	45.0	$	45.0	$	41.6	$	41.6
One to five years		12.2		12.4		4.7		4.7
Six to ten years		7.5		7.8		1.2		1.2
Greater than ten years		21.4		21.5		9.5		9.3
Total debt securities	$	86.1	$	86.7	$	57.0	$	56.8

Sales of Securities: For the three months ended March 31, 2010 and 2009, realized gains and losses recognized on the sale of available-for-sale securities are as follows:


	Three Months Ended March 31, 2010						Three Months Ended March 31, 2009
(Millions of Dollars)		Realized Gains		Realized Losses		Net Realized Gains		Realized Gains		Realized Losses		Net Realized Losses
NU	$	0.1	$	-	$	0.1	$	0.6	$	(1.0)	$	(0.4)
WMECO		-		-		-		-		-		-

Realized gains and losses on available-for-sale-securities are recorded in Other income, net for the NU supplemental benefit trust and in Other long-term assets for the WMECO spent nuclear fuel trust. NU utilizes the specific identification basis method for the NU supplemental benefit trust securities and the average cost basis method for the WMECO spent nuclear fuel trust to compute the realized gains and losses on the sale of available-for-sale securities. Proceeds from the sale of these securities, including proceeds from short-term investments, totaled $21.3 million and $52.9 million for the three months ended March 31, 2010 and 2009, respectively. WMECO's portion of these proceeds totaled $11.1 million and $35.7 million for the three months ended March 31, 2010 and 2009, respectively. Proceeds from the sales of securities are used to purchase new securities.

Fair Value Measurements: The following table presents the marketable securities recorded at fair value on a recurring basis by the level in which they are classified within the fair value hierarchy:


	NU				WMECO
	As of March 31, 2010		As of December 31, 2009		As of March 31, 2010		As of December 31, 2009
Level 1:
Exchange Traded Funds	$	33.7	$	32.0	$	-	$	-
High yield bond fund		3.3		3.3		-		-
Money market funds		20.7		8.9		17.6		6.6
Total Level 1		57.7		44.2		17.6		6.6
Level 2:
U.S. Government issued debt securities (agency and treasury)		23.3		29.9		12.0		17.0
Corporate debt securities		24.2		25.1		15.4		17.4
Municipal bonds		10.8		10.8		10.5		10.6
Asset backed securities		6.5		6.1		0.7		0.9
Other fixed income securities		1.2		5.0		0.6		4.3
Total Level 2		66.0		76.9		39.2		50.2
Total Marketable Securities	$	123.7	$	121.1	$	56.8	$	56.8

Fixed income securities classified as Level 2 in the fair value hierarchy are valued using outside pricing services and these values are validated by the trustee. U.S. Treasury and Agency bonds are valued using market approaches that incorporate transactions for the same or similar bonds and adjustments for yields and maturity dates. Corporate bonds are valued using a market approach, utilizing recent trades of the same or similar instrument and also incorporating yield curves, credit spreads and specific bond terms and conditions. Municipal bonds are valued using a market approach that incorporates reported trades and benchmark yields. Asset-backed securities include collateralized mortgage obligations, commercial mortgage-backed securities, and securities collateralized by auto loans, credit card loans or receivables. Asset-backed securities are valued using recent trades of similar instruments, prepayment assumptions, yield curves, issuance and maturity dates and tranche information. Other bonds are valued using pricing models, quoted prices of securities with similar characteristics, and discounted cash flows.

Not included in the tables above are $9.6 million and $11.6 million of cash equivalents as of March 31, 2010 and December 31, 2009, respectively, held by NU parent in an unrestricted money market account and included in Cash and cash equivalents on the accompanying unaudited condensed consolidated balance sheets of NU, which are classified as Level 1 in the fair value hierarchy.

10.

SEGMENT INFORMATION

Presentation: NU is organized between the Regulated companies’ segments and NU Enterprises based on a combination of factors, including the characteristics of each business' products and services, the sources of operating revenues and expenses and the regulatory environment in which each segment operates. Cash flows for total investments in plant included in the segment information below are cash capital expenditures that do not include amounts incurred but not paid, cost of removal, AFUDC related to equity funds, and the capitalized portions of pension and PBOP expense or income.

The Regulated companies’ segments, including the electric distribution and transmission segments, as well as the natural gas distribution segment (Yankee Gas), represented approximately 99 percent of NU's total consolidated revenues for the three-month periods ended March 31, 2010 and 2009. PSNH's distribution segment includes its generation activities. CL&P's, PSNH's and WMECO's complete unaudited condensed consolidated financial statements are included in this combined Quarterly Report on Form 10-Q. Also included in this combined Quarterly Report on Form 10-Q is detailed information regarding CL&P's, PSNH's, and WMECO's transmission segments.

NU Enterprises is comprised of the following: 1) Select Energy (wholesale contracts), 2) Boulos, 3) NGS, 4) NGS Mechanical, 5) SECI, and 6) NU Enterprises parent. As a result of the sale of NU Enterprises' retail marketing and competitive generation businesses, the financial information used by management was reduced to the remaining wholesale contracts, the operations of the remaining electrical contracting business and NU Enterprises parent. The remaining operations of NU Enterprises have been aggregated and presented as one business for the three months ended March 31, 2010 and 2009.

Other in the tables below primarily consists of 1) the results of NU parent, which includes other income related to the equity in earnings of NU parent's subsidiaries and interest income from the NU Money Pool, which are both eliminated in consolidation, and interest income and expense related to the cash and debt of NU parent, respectively, 2) the revenues and expenses of NU's service companies, most of which are eliminated in consolidation, and 3) the results of other subsidiaries, which are comprised of RRR (a real estate subsidiary), the non-energy-related subsidiaries of Yankee (Yankee Energy Services Company and Yankee Energy Financial Services Company) and the remaining operations of HWP that were not exited as part of the sale of the competitive generation business in 2006 and the sale of its transmission business to WMECO in December 2008.

Regulated companies' revenues from the sale of electricity and natural gas primarily are derived from residential, commercial and industrial customers and are not dependent on any single customer.

NU's segment information for the three months ended March 31, 2010 and 2009 is as follows (some amounts may not agree between the financial statements and the segment schedules due to rounding):


	For the Three Months Ended March 31, 2010
	Regulated Companies
	Distribution
(Millions of Dollars)	Electric		Natural Gas		Transmission		NU Enterprises		Other		Eliminations		Total
Operating revenues	$	1,000.0	$	171.7	$	153.7	$	19.3	$	104.8	$	(110.1)	$	1,339.4
Depreciation and amortization		(103.1)		(3.6)		(20.3)		(0.1)		(3.7)		1.0		(129.8)
Other operating expenses		(801.4)		(129.7)		(47.0)		(13.5)		(102.3)		111.0		(982.9)
Operating income/(loss)		95.5		38.4		86.4		5.7		(1.2)		1.9		226.7
Interest expense, net of AFUDC		(36.5)		(4.9)		(19.5)		(0.4)		(7.2)		1.2		(67.3)
Interest income		0.8		-		0.1		-		1.3		(1.4)		0.8
Other income, net		4.5		-		2.6		-		111.7		(111.5)		7.3
Income tax (expense)/benefit		(35.2)		(13.9)		(28.9)		(3.0)		1.4		(0.3)		(79.9)
Net income		29.1		19.6		40.7		2.3		106.0		(110.1)		87.6
Net income attributable to noncontrolling interest		(0.8)		-		(0.6)		-		-		-		(1.4)
Net income attributable to controlling interest	$	28.3	$	19.6	$	40.1	$	2.3	$	106.0	$	(110.1)	$	86.2
Total assets	$	8,795.7	$	1,364.9	$	3,331.1	$	115.7	$	5,800.1	$	(5,302.1)	$	14,105.4
Cash flows for total investments in plant	$	115.7	$	12.9	$	55.6	$	-	$	18.3	$	-	$	202.5


	For the Three Months Ended March 31, 2009
	Regulated Companies
	Distribution
(Millions of Dollars)	Electric		Natural Gas		Transmission		NU Enterprises		Other		Eliminations		Total
Operating revenues	$	1,246.0	$	201.8	$	134.2	$	20.7	$	107.1	$	(116.3)	$	1,593.5
Depreciation and amortization		(127.3)		(6.7)		(17.4)		(0.1)		(3.3)		0.2		(154.6)
Other operating expenses		(1,029.2)		(157.7)		(39.5)		(9.8)		(98.3)		112.9		(1,221.6)
Operating income		89.5		37.4		77.3		10.8		5.5		(3.2)		217.3
Interest expense, net of AFUDC		(37.9)		(6.4)		(17.6)		(1.2)		(10.1)		2.2		(71.0)
Interest income		0.9		-		0.1		-		2.5		(2.3)		1.2
Other income/(loss), net		3.8		-		(0.8)		-		81.9		(81.9)		3.0
Income tax (expense)/benefit		(15.6)		(11.7)		(23.0)		(3.8)		3.3		(0.6)		(51.4)
Net income		40.7		19.3		36.0		5.8		83.1		(85.8)		99.1
Net income attributable to noncontrolling interest		(0.8)		-		(0.6)		-		-		-		(1.4)
Net income attributable to controlling interest	$	39.9	$	19.3	$	35.4	$	5.8	$	83.1	$	(85.8)	$	97.7
Cash flows for total investments in plant	$	128.7	$	13.3	$	59.4	$	-	$	7.5	$	-	$	208.9

The information related to the distribution and transmission segments for CL&P, PSNH and WMECO for the three months ended March 31, 2010 and 2009 is as follows:


	CL&P - For the Three Months Ended March 31, 2010
(Millions of Dollars)	Distribution		Transmission		Total
Operating revenues	$	671.2	$	123.8	$	795.0
Depreciation and amortization		(75.8)		(16.7)		(92.5)
Other operating expenses		(541.3)		(35.7)		(577.0)
Operating income		54.1		71.4		125.5
Interest expense, net of AFUDC		(22.4)		(16.1)		(38.5)
Interest income		0.5		0.1		0.6
Other income, net		2.2		2.1		4.3
Income tax expense		(19.4)		(24.1)		(43.5)
Net income	$	15.0	$	33.4	$	48.4
Total assets	$	5,664.8	$	2,605.5	$	8,270.3
Cash flows for total investments in plant	$	63.8	$	33.9	$	97.7


	CL&P - For the Three Months Ended March 31, 2009
(Millions of Dollars)	Distribution		Transmission		Total
Operating revenues	$	843.8	$	110.7	$	954.5
Depreciation and amortization		(85.6)		(14.4)		(100.0)
Other operating expenses		(709.5)		(29.6)		(739.1)
Operating income		48.7		66.7		115.4
Interest expense, net of AFUDC		(22.5)		(15.2)		(37.7)
Interest income		0.7		0.1		0.8
Other income/(loss), net		2.9		(1.0)		1.9
Income tax expense		(7.4)		(19.9)		(27.3)
Net income	$	22.4	$	30.7	$	53.1
Cash flows for total investments in plant	$	77.7	$	38.6	$	116.3


	PSNH - For the Three Months Ended March 31, 2010
(Millions of Dollars)	Distribution		Transmission		Total
Operating revenues	$	238.9	$	19.7	$	258.6
Depreciation and amortization		(20.1)		(2.6)		(22.7)
Other operating expenses		(188.4)		(7.6)		(196.0)
Operating income		30.4		9.5		39.9
Interest expense, net of AFUDC		(10.3)		(2.1)		(12.4)
Interest income		0.2		-		0.2
Other income, net		1.8		0.4		2.2
Income tax expense		(11.0)		(3.1)		(14.1)
Net income	$	11.1	$	4.7	$	15.8
Total assets	$	2,285.0	$	450.4	$	2,735.4
Cash flows for total investments in plant	$	45.7	$	8.4	$	54.1


	PSNH - For the Three Months Ended March 31, 2009
(Millions of Dollars)	Distribution		Transmission		Total
Operating revenues	$	291.3	$	16.4	$	307.7
Depreciation and amortization		(32.7)		(2.1)		(34.8)
Other operating expenses		(230.1)		(6.7)		(236.8)
Operating income		28.5		7.6		36.1
Interest expense, net of AFUDC		(10.9)		(1.7)		(12.6)
Interest income		0.1		-		0.1
Other income, net		1.1		0.3		1.4
Income tax expense		(5.3)		(2.2)		(7.5)
Net income	$	13.5	$	4.0	$	17.5
Cash flows for total investments in plant	$	39.2	$	13.3	$	52.5


	WMECO - For the Three Months Ended March 31, 2010
(Millions of Dollars)	Distribution		Transmission		Total
Operating revenues	$	90.0	$	10.2	$	100.2
Depreciation and amortization		(7.3)		(1.0)		(8.3)
Other operating expenses		(71.8)		(3.7)		(75.5)
Operating income		10.9		5.5		16.4
Interest expense, net of AFUDC		(3.7)		(1.2)		(4.9)
Interest income		0.1		-		0.1
Other income, net		0.4		0.1		0.5
Income tax expense		(4.7)		(1.7)		(6.4)
Net income	$	3.0	$	2.7	$	5.7
Total assets	$	851.8	$	271.6	$	1,123.4
Cash flows for total investments in plant	$	6.2	$	12.9	$	19.1


	WMECO - For the Three Months Ended March 31, 2009
(Millions of Dollars)	Distribution		Transmission		Total
Operating revenues	$	111.0	$	7.1	$	118.1
Depreciation and amortization		(9.1)		(0.8)		(9.9)
Other operating expenses		(89.7)		(3.2)		(92.9)
Operating income		12.2		3.1		15.3
Interest expense, net of AFUDC		(4.4)		(0.8)		(5.2)
Interest income		0.1		-		0.1
Other income, net		(0.2)		(0.1)		(0.3)
Income tax expense, net		(2.9)		(0.9)		(3.8)
Net income	$	4.8	$	1.3	$	6.1
Cash flows for total investments in plant	$	11.8	$	7.4	$	19.2

11.

COMMON SHAREHOLDERS' EQUITY AND NONCONTROLLING INTEREST (NU)

A summary of the changes in common shareholders' equity and noncontrolling interest of NU for the three months ended March 31, 2010 and 2009 is as follows:


	For the Three Months Ended March 31,
	2010				2009
(Millions of Dollars)	Common Shareholders' Equity		Noncontrolling Interest		Common Shareholders' Equity		Noncontrolling Interest
Balance, beginning of period	$	3,577.9	$	116.2	$	3,020.3	$	116.2
Net income		87.6		-		99.1		-
Dividends on common shares		(45.5)		-		(37.3)		-
Dividends on preferred shares of CL&P		(1.4)		(1.4)		(1.4)		(1.4)
Issuance of common shares		5.2		-		387.4		-
Capital stock expenses, net		-		-		(12.6)		-
Other transactions, net		0.7		-		0.4		-
Net income attributable to noncontrolling interest		-		1.4		-		1.4
Other comprehensive income (Note 5)		0.7		-		0.2		-
Balance, end of period	$	3,625.2	$	116.2	$	3,456.1	$	116.2

For the three months ended March 31, 2010 and 2009, there was no change in NU parent's 100 percent ownership of the common equity of CL&P.

12.

SUBSEQUENT EVENTS (CL&P, YANKEE GAS)

On April 1, 2010, CL&P remarketed $62 million of PCRBs. The PCRBs, which mature on May 1, 2031, carry a coupon of 1.4 percent during the current one-year fixed-rate period and are subject to a mandatory tender for purchase on April 1, 2011, after which CL&P can remarket the bonds.

On April 22, 2010, Yankee Gas issued $50 million of Series K first mortgage bonds with a coupon rate of 4.87 percent and a maturity date of April 1, 2020. The proceeds of these bonds were used to repay short-term borrowings and to fund ongoing capital investment programs.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Trustees and Shareholders of Northeast Utilities:

We have reviewed the accompanying condensed consolidated balance sheet of Northeast Utilities and subsidiaries (the "Company") as of March 31, 2010, and the related condensed consolidated statements of income and cash flows for the three-months ended March 31, 2010 and 2009. These interim financial statements are the responsibility of the Company’s management.

We conducted our reviews in accordance with the standards of the Public Company Accounting Oversight Board (United States). A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the Public Company Accounting Oversight Board (United States), the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.

Based on our reviews, we are not aware of any material modifications that should be made to such condensed consolidated interim financial statements for them to be in conformity with accounting principles generally accepted in the United States of America.

We have previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet and consolidated statement of capitalization of Northeast Utilities and subsidiaries as of December 31, 2009, and the related consolidated statements of income, comprehensive income, shareholders’ equity, and cash flows for the year then ended (not presented herein); and in our report dated February 26, 2010, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying condensed consolidated balance sheet as of December 31, 2009 is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.


/s/	Deloitte & Touche LLP
	Deloitte & Touche LLP

Hartford, Connecticut

May 7, 2010

NORTHEAST UTILITIES AND SUBSIDIARIES

Management's Discussion and Analysis of
Financial Condition and Results of Operations

The following discussion and analysis should be read in conjunction with our unaudited condensed consolidated financial statements and related combined notes included in this Quarterly Report on Form 10-Q and the 2009 Form 10-K. References in this Form 10-Q to "NU," the "Company," "we," "us" and "our" refer to Northeast Utilities and its consolidated subsidiaries. All per share amounts are reported on a fully diluted basis.

Refer to the Glossary of Terms included in this combined Quarterly Report on Form 10-Q for abbreviations and acronyms used throughout this Management's Discussion and Analysis of Financial Condition and Results of Operations.

The only common equity securities that are publicly traded are common shares of NU. The earnings and EPS of each business discussed below do not represent a direct legal interest in the assets and liabilities allocated to such business but rather represent a direct interest in our assets and liabilities as a whole. EPS by business is a financial measure not recognized under GAAP that is calculated by dividing the net income or loss attributable to controlling interest of each business by the weighted average fully diluted NU common shares outstanding for the period. We use this non-GAAP financial measure to evaluate earnings results and to provide details of earnings results and guidance by business. We believe that this measurement is useful to investors to evaluate the actual and projected financial performance and contribution of our businesses. This non-GAAP financial measure should not be considered as an alternative to our consolidated fully diluted EPS determined in accordance with GAAP as an indicator of operating performance.

Reconciliations of the above non-GAAP financial measures to the most directly comparable GAAP measures of consolidated fully diluted EPS and Net income attributable to controlling interest are included under "Financial Condition and Business Analysis-Overview-Consolidated" and "Financial Condition and Business Analysis-Future Outlook" in Management's Discussion and Analysis, herein.

Forward-Looking Statements: From time to time we make statements concerning our expectations, beliefs, plans, objectives, goals, strategies, assumptions of future events, financial performance or growth and other statements that are not historical facts. These statements are "forward-looking statements" within the meaning of the Private Securities Litigation Reform Act of 1995. You can generally identify our forward-looking statements through the use of words or phrases such as "estimate," "expect," "anticipate," "intend," "plan," "project," "believe," "forecast," "should," "could," and other similar expressions. Forward-looking statements are based on the current expectations, estimates, assumptions or projections of management and are not guarantees of future performance. These expectations, estimates, assumptions or projections may vary materially from actual results. Accordingly, any such statements are qualified in their entirety by reference to, and are accompanied by, the following important factors that could cause our actual results to differ materially from those contained in our forward-looking statements, including, but not limited to:

actions or inaction by local, state and federal regulatory bodies

changes in business and economic conditions, including their impact on interest rates, bad debt expense, and demand for our products and services

changes in weather patterns

changes in laws, regulations or regulatory policy

changes in levels and timing of capital expenditures

disruptions in the capital markets or other events that make our access to necessary capital more difficult or costly

developments in legal or public policy doctrines

technological developments

changes in accounting standards and financial reporting regulations

fluctuations in the value of our remaining competitive electricity positions

actions of rating agencies, and

other presently unknown or unforeseen factors.

Other risk factors are detailed in our reports filed with the SEC and updated from time to time, and we encourage you to consult such disclosures.

All such factors are difficult to predict, contain uncertainties which may materially affect our actual results and are beyond our control. You should not place undue reliance on the forward-looking statements, each speaks only as of the date on which such statement is made, and we undertake no obligation to update any forward-looking statement or statements to reflect events or circumstances after the date on which such statement is made or to reflect the occurrence of unanticipated events. New factors emerge from time to time and it is not possible for management to predict all of such factors, nor can management assess the impact of each such factor on the business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statements. For more information, see Item 1A, Risk Factors, included in this Quarterly Report on Form 10-Q and in our 2009 Form 10-K. This Quarterly Report on Form 10-Q and our 2009 Form 10-K also describe material contingencies and critical accounting policies and estimates in the respective Management’s Discussion and Analysis and Combined Notes to Consolidated Financial Statements. We encourage you to review these items.

Financial Condition and Business Analysis

Executive Summary

The following items in this executive summary are explained in more detail in this Quarterly Report:

Results and Outlook:

We earned $86.2 million, or $0.49 per share, in the first quarter of 2010, compared with $97.7 million, or $0.60 per share, in the first quarter of 2009. First quarter 2010 results reflect a decline in retail electric sales as a result of warmer than normal weather and a net after-tax charge of $3 million, or $0.02 per share, associated with the enactment of the 2010 Healthcare Act in March.

Our Regulated companies earned $88 million, or $0.50 per share, in the first quarter of 2010, compared with $94.6 million, or $0.58 per share, in the first quarter of 2009.

Earnings from the distribution segment of our Regulated companies (which also include Yankee Gas and the generation business of PSNH) totaled $47.9 million, or $0.27 per share, in the first quarter of 2010, compared with $59.2 million, or $0.36 per share, in the first quarter of 2009. Earnings from the transmission segment of our Regulated companies totaled $40.1 million, or $0.23 per share, in the first quarter of 2010, compared with $35.4 million, or $0.22 per share, in the first quarter of 2009. The decrease in distribution segment results was due primarily to lower revenues resulting from a decline in retail electric sales and higher employee benefit costs. The higher transmission segment results were due to an increased investment in this segment as we continued to build out our transmission infrastructure to meet our customers' and the region's reliability needs.

Our competitive businesses, which are held by NU Enterprises, earned $2.3 million, or $0.01 per share, in the first quarter of 2010, compared with $5.8 million, or $0.04 per share, in the first quarter of 2009. NU Enterprises recorded a $0.4 million after-tax mark-to-market loss in the first quarter of 2010, compared with a $3.2 million after-tax mark-to-market gain in the first quarter of 2009.

NU parent and other companies recorded net expenses of $4.1 million, or $0.02 per share, in the first quarter of 2010, compared with net expenses of $2.7 million, or $0.02 per share, in the first quarter of 2009 due primarily to a $0.6 million net after-tax charge associated with the 2010 Healthcare Act, a $0.6 million after-tax environmental reserve increase at HWP, and the absence in 2010 of a $0.7 million favorable tax audit settlement.

We reaffirmed consolidated 2010 earnings of between $1.80 per share and $2.00 per share, including distribution segment earnings of between $0.95 per share and $1.05 per share, transmission segment earnings of between $0.90 per share and $0.95 per share, competitive business earnings of between zero and $0.05 per share, and net expenses at NU parent and other companies of approximately $0.05 per share.

Strategy, Regulatory and Other Items:

On January 8, 2010, CL&P filed an application with the DPUC to raise distribution rates by $133.4 million to be effective July 1, 2010, and by an additional $44.2 million to be effective July 1, 2011. CL&P proposed that the first year’s increase be deferred until January 1, 2011 and that approximately $67 million of cash revenue requirements for the second half of 2010 be deferred and recovered from CL&P customers between January 1, 2011 and June 30, 2012. Hearings were completed and final briefs were filed in April 2010 and a final decision is expected in June 2010.

On February 25, 2010, a severe storm with high winds caused nearly 270,000 PSNH customers to lose power. PSNH estimates that the cost of restoration was approximately $24 million. On March 13, 2010, another severe storm with high winds caused widespread damage to CL&P’s overhead facilities in southwest Connecticut and caused 160,000 CL&P customers to lose power. CL&P estimates that the cost of restoration was approximately $21 million. Both CL&P and PSNH expect the costs associated with these major storms will be recoverable through a combination of insurance proceeds, customer-funded reserves that are established for the purpose of recovering major storm costs, and current distribution revenues. On March 17, 2010, the DPUC opened a docket to investigate the restoration efforts of CL&P and UI following the outages.

On March 16, 2010, the CSC approved CL&P’s application to build the 12-mile section of the proposed GSRP located in Connecticut. WMECO’s application to build the 23-mile Massachusetts portion of the GSRP from Ludlow, Massachusetts to the Connecticut border is pending before the EFSB with a decision expected in the third quarter of 2010. GSRP is currently expected to cost $714 million.

NU, through a newly-formed holding company, NUTV, and NSTAR Transmission Ventures, Inc., a subsidiary of NSTAR, jointly formed a limited liability company, NPT, to construct, own and operate the Northern Pass line. Pursuant to NPT’s operating agreement, NUTV holds a 75 percent interest in NPT with NSTAR holding the remaining 25 percent.

On March 31, 2010, CL&P filed with the DPUC an AMI and dynamic pricing plan that included a cost-benefit analysis. CL&P concluded that a full deployment of AMI meters accompanied by dynamic pricing options for all CL&P customers would be cost beneficial under the base case scenario. The capital expenditures for the installation of the meters is estimated at $296 million.

On April 30, 2010, PSNH, the NHPUC staff and the Office of Consumer Advocate submitted a proposed settlement of a distribution rate case PSNH had filed on June 30, 2009 with the NHPUC. Under the proposed settlement, the parties agreed to a net distribution rate increase of $45.5 million on an annualized basis to be effective July 1, 2010, and annualized distribution rate adjustments projected at negative $2.9 million, and positive $9.5 million and $11.1 million on July 1 of each of the three subsequent years, respectively. The $45.5 million increase is in addition to the $25.6 million temporary increase that became effective August 1, 2009. The $45.5 million increase includes $13.7 million to reconcile the difference between the temporary rates and the permanent rates back to August 1, 2009. Another provision of the settlement was that the authorized regulatory ROE on distribution only plant continues at the previously allowed level of 9.67 percent. A decision by the NHPUC is expected in June 2010.

In the legislative session, which closed May 5, 2010, the Connecticut Legislature passed SB 493, which, if it becomes law, would reorganize the DPUC, launch a significant solar generation initiative, allow distribution companies to manage a portfolio that would provide some of their standard service supply and implement reduced distribution rates for low-income customers. We do not believe that the bill will have an adverse financial impact on us. In addition, the Connecticut legislature approved a state budget for the 2010-2011 fiscal year. To fund a revenue gap, the budget calls for the issuance of $956 million of economic recovery revenue bonds that would be amortized over eight years. These bonds would be repaid through a charge on customer bills of CL&P and other Connecticut electric utility companies.

Liquidity:

We completed $145 million of new debt issuances in the first four months of 2010, consisting of $95 million at WMECO and $50 million at Yankee Gas. Additionally, CL&P remarketed $62 million of tax-exempt PCRBs. We anticipate no additional long-term debt issuances in 2010.

Our cash capital expenditures totaled $202.5 million in the first quarter of 2010, compared with $208.9 million in the first quarter of 2009. We continue to project total capital expenditures of approximately $1.1 billion in 2010.

We had cash flows provided by operating activities of $159.1 million in the first quarter of 2010, compared with $77.5 million in the first quarter of 2009 (all amounts are net of RRB payments, which are included in financing activities). The improved cash flows were due primarily to the absence in 2010 of costs at PSNH and WMECO related to the major storm in December 2008 that were paid to vendors in the first quarter of 2009, offset by an increase in income tax payments largely attributable to the absence of bonus depreciation tax deductions in the first quarter of 2010. We project consolidated cash flows provided by operating activities, net of RRB payments, of approximately $650 million in 2010, which is $50 million lower than our previous projections due primarily to the 2010 severe storm costs.

Our cash and cash equivalents totaled $30 million as of March 31, 2010, compared with $27 million as of December 31, 2009. As of March 31, 2010, we had $694.1 million of aggregate borrowing availability on our revolving credit lines, compared with $702.8 million as of December 31, 2009.

Overview

Consolidated: We earned $86.2 million, or $0.49 per share, in the first quarter of 2010, compared with $97.7 million, or $0.60 per share, in the first quarter of 2009. EPS for both years reflect the issuance of nearly 19 million common shares on March 20, 2009. First quarter 2010 results were negatively impacted by a decline in the distribution segment retail electric sales as a result of warmer than normal weather. First quarter 2010 results also reflect a net after-tax charge of $3 million, or $0.02 per share, associated with the enactment of the 2010 Healthcare Act in March.

The 2010 Healthcare Act includes a provision that eliminated the tax deductibility of certain PBOP contributions equal to the amount of the federal subsidy received by companies like NU, which sponsor retiree health care benefit plans with a prescription drug benefit that is actuarially equivalent to Medicare Part D. We recorded approximately $18 million in charges to Income tax expense on the accompanying unaudited condensed consolidated statement of income for the three months ended March 31, 2010 as a result of the 2010 Healthcare Act. This represented the loss of previously recognized tax benefits. Since the electric and natural gas distribution companies are cost-of-service and rate regulated, some of these costs are able to be deferred and recovered through future rates. As a result, we recognized a deferred asset of approximately $15 million, net of tax, which reflects the probable recovery in future rates of these previously recognized lost tax benefits. Therefore, only the net amount of $3 million resulted in a charge to earnings for the three months ended March 31, 2010.

As a result of the elimination of the tax deduction in 2010, NU will not be able to recognize approximately $2 million of current period benefits. Therefore, NU's projected 2010 effective tax rate, including these discrete items expected to occur during 2010, is estimated to be approximately 38 percent. Excluding the impacts of discrete items, NU's 2010 effective tax rate would be estimated to be approximately 36 percent.

A summary of our earnings by business, which also reconciles the non-GAAP financial measures of consolidated non-GAAP earnings and EPS, as well as EPS by business, to the most directly comparable GAAP measures of consolidated net income attributable to controlling interest and fully diluted EPS, for the first quarters of 2010 and 2009 is as follows:


	For the Three Months Ended March 31,
(Millions of Dollars, except	2010				2009
Per share amounts)	Amount		Per Share		Amount		Per Share
Net income attributable to controlling interest (GAAP)	$	86.2	$	0.49	$	97.7	$	0.60

Regulated companies	$	88.0	$	0.50	$	94.6	$	0.58
Competitive businesses		2.3		0.01		5.8		0.04
NU parent and other companies		(4.1)		(0.02)		(2.7)		(0.02)
Net income attributable to controlling interest (GAAP)	$	86.2	$	0.49	$	97.7	$	0.60

Regulated Companies: Our Regulated companies operate in two segments: electric transmission and electric and natural gas distribution, with PSNH generation included in its distribution segment. A summary of our Regulated companies' earnings by segment for the first quarters of 2010 and 2009 is as follows:


	For the Three Months Ended March 31,
(Millions of Dollars)	2010		2009
CL&P Transmission	$	32.7	$	30.1
PSNH Transmission		4.7		4.0
WMECO Transmission		2.7		1.3
Total Transmission		40.1		35.4
CL&P Distribution		14.3		21.6
PSNH Distribution		11.1		13.5
WMECO Distribution		2.9		4.8
Yankee Gas		19.6		19.3
Total Distribution		47.9		59.2
Net Income - Regulated Companies	$	88.0	$	94.6

The higher first quarter 2010 transmission segment earnings reflect an increased investment in this segment as we continued to build out our transmission infrastructure to meet our customers' and the region's reliability needs, partially offset by a $0.8 million after-tax charge associated with the 2010 Healthcare Act.

CL&P’s first quarter 2010 distribution segment earnings were $7.3 million lower than the same period in 2009 due primarily to lower revenues resulting from a 4.9 percent decline in retail electric sales, higher employee benefit costs, lower Energy Independence Act incentives, and the absence in 2010 of lower state income taxes in the first quarter of 2009 that resulted from the closure of the normal audit process, partially offset by lower operating and maintenance costs. For the 12 months ended March 31, 2010, CL&P’s distribution segment regulatory ROE was 6.8 percent, well below its current authorized level of 9.4 percent. The Company expects it to continue to deteriorate before it improves starting in the second half of 2010 after the DPUC issues its decision on CL&P’s request to raise distribution rates effective July 1, 2010. CL&P’s request includes an authorized regulatory ROE of 10.5 percent.

PSNH’s first quarter 2010 distribution segment earnings were $2.4 million lower than the same period in 2009 due primarily to lower revenues resulting from a 5.3 percent decline in retail electric sales, higher employee benefit costs, higher income tax expense totaling $1 million associated with the 2010 Healthcare Act, and higher depreciation, property taxes, and interest expense. These items were partially offset by the $25.6 million annualized temporary distribution rate increase that took effect August 1, 2009. For the 12 months ended March 31, 2010, PSNH’s distribution segment regulatory ROE was 6.6 percent (including generation). PSNH reached a settlement with the NHPUC staff and the Office of Consumer Advocate with respect to PSNH’s permanent distribution rate request. The settlement was submitted to the NHPUC for approval on April 30, 2010. If the settlement is approved, PSNH’s regulatory ROE will improve over the remainder of 2010.

WMECO’s first quarter 2010 distribution segment earnings were $1.9 million lower than the same period in 2009 due primarily to lower revenues resulting from a 4.4 percent decline in retail electric sales, higher employee benefit costs, higher administrative and general expenses, and higher depreciation and property taxes. These items were partially offset by lower interest expense. For the 12 months ended March 31, 2010, WMECO’s distribution segment regulatory ROE was 7.2 percent and for 2010, we expect it to be approximately 6 percent.

Yankee Gas’ first quarter 2010 earnings were $0.3 million higher than the same period in 2009 due primarily to lower interest expense, depreciation, and operating costs mostly offset by lower revenues resulting from a 3.5 percent decline in firm natural gas sales and higher employee benefit costs. For the 12 months ended March 31, 2010, Yankee Gas’ regulatory ROE was 6.7 percent and for 2010, we now expect Yankee Gas to earn approximately 8 percent, down from the 9 percent we had previously anticipated. The expected decline in Yankee Gas' 2010 regulatory ROE is driven by warmer than normal temperatures during the first three months of 2010.

For the distribution segment of our Regulated companies, a summary of changes in CL&P, PSNH and WMECO retail electric GWh sales and Yankee Gas firm natural gas sales for the first quarter of 2010 as compared to the same period in 2009 on an actual and weather normalized basis (using a 30-year average) is as follows:


	For the Three Months Ended March 31, 2010 Compared to 2009
	Electric								Firm Natural Gas
	CL&P		PSNH		WMECO		Total		Yankee Gas
	Percentage Increase/ (Decrease)	Weather Normalized Percentage Increase/ (Decrease)	Percentage Increase/ (Decrease)	Weather Normalized Percentage Increase/ (Decrease)	Percentage Decrease	Weather Normalized Percentage Increase/ (Decrease)	Percentage Decrease	Weather Normalized Percentage Decrease	Percentage Increase/ (Decrease)	Weather Normalized Percentage Increase
Residential	(6.6)%	(1.9)%	(6.1)%	(1.8)%	(2.8)%	1.4 %	(6.1)%	(1.5)%	(5.5)%	6.6%
Commercial	(4.8)%	(3.9)%	(4.9)%	(3.7)%	(5.1)%	(4.6)%	(4.9)%	(4.0)%	(6.1)%	5.4%
Industrial	4.2 %	4.2 %	(4.7)%	(4.7)%	(4.3)%	(4.3)%	-	-	3.5 %	7.7%
Other	(8.0)%	(8.0)%	4.4 %	4.4 %	(45.1)%	(45.1)%	(10.6)%	(10.6)%	-	-
Total	(4.9)%	(2.3)%	(5.3)%	(3.0)%	(4.4)%	(2.3)%	(4.9)%	(2.5)%	(3.5)%	6.4%

A summary of our retail electric sales in GWh for CL&P, PSNH and WMECO and firm natural gas sales in million cubic feet for Yankee Gas for the first quarters of 2010 and 2009 is as follows:


	For the Three Months Ended March 31,
	Electric			Firm Natural Gas
	2010	2009	Percentage Decrease	2010	2009	Percentage Increase/ (Decrease)
Residential	3,896	4,148	(6.1)%	6,104	6,461	(5.5)%
Commercial	3,456	3,633	(4.9)%	5,882	6,267	(6.1)%
Industrial	1,008	1,009	-	4,457	4,306	3.5 %
Other	88	98	(10.6)%	-	-	-
Total	8,448	8,888	(4.9)%	16,443	17,034	(3.5)%

First quarter 2010 actual and weather normalized retail electric sales for all three electric companies were lower than the same period in 2009. Residential sales were down for all three electric companies, due in large part to the warmer than normal weather in the first quarter of 2010. Heating degree days in Connecticut and Western Massachusetts were down 13.5 percent compared to last year and 11.6 percent below normal. Heating degree days in New Hampshire were down 16 percent compared to last year and 12.1 percent below normal. The severe storms with high winds that produced extended outages for approximately 430,000 CL&P and PSNH customers in both Connecticut and New Hampshire in the first quarter of 2010 were estimated to have had a minimal effect on residential sales.

Commercial sales were down for all three electric companies due to the warmer than normal weather and prolonged effects of the economic recession, which continued to be felt by commercial customers as they reduced both shifts and operating hours. Industrial sales declined in both New Hampshire and Western Massachusetts; however, Connecticut saw an increase in industrial sales. We continue to believe that the decline in industrial sales in New Hampshire and Western Massachusetts is the result of reduced days of operations and reduced worker hours as a result of the current economic climate. Connecticut industrial sales increased in the first quarter compared to the same period last year, which we believe was due to an exceptionally low level of output in response to reduced demand. We believe that a portion of these reduced commercial and industrial sales may be regained when the economy recovers. Further, commercial and industrial sales in the first quarter of 2010 were negatively impacted by additional installation of gas-fired distributed generation and utilization of conservation and load management programs.

Firm natural gas sales were lower for both residential and commercial customers in the first quarter of 2010 compared to the same period in 2009. The decrease in residential and commercial sales can be attributed to the warmer than normal weather in the first quarter of 2010. On a weather normalized basis, Yankee Gas residential and commercial volumes were higher in the first quarter of 2010 compared to the same period in 2009. Yankee Gas industrial sales were higher on both an actual and weather normalized basis in the first quarter of 2010 than in the same period in 2009. Commercial and industrial sales continue to benefit from the addition of gas-fired distributed generation in Yankee Gas’ service territory.

Our expense related to uncollectible receivable balances (our uncollectibles expense) is influenced by the economic conditions of our region. Fluctuations in our uncollectibles expense are mitigated, however, from an earnings perspective because a portion of the total uncollectibles expense for each of the electric distribution companies is allocated to the respective company’s energy supply rate and recovered through its tariffs. Additionally, for CL&P and Yankee Gas, write-offs of uncollectible receivable balances attributable to qualified customers under financial or medical duress (or hardship customers) are fully recovered through their respective tariffs. For the first quarter of 2010, our total uncollectibles expense was approximately $5 million higher than the same period in 2009 due entirely to higher uncollectible receivable balances for hardship customers at CL&P. This increase in uncollectibles expense did not impact earnings and will be recovered through CL&P's tariffs. The first quarter 2010 uncollectibles expense is consistent with our expectations and we continue to expect our 2010 uncollectibles expense that impacts earnings to be significantly lower than it was in 2009.

Competitive Businesses: NU Enterprises, which continues to manage to completion Select Energy’s remaining wholesale marketing contracts and to manage its electrical contracting business, earned $2.3 million, or $0.01 per share, in the first quarter of 2010, compared with earnings of $5.8 million, or $0.04 per share, in the first quarter of 2009. Competitive business earnings in the first

quarter of 2010 included an after-tax mark-to-market loss of $0.4 million, compared with an after-tax mark-to-market gain of $3.2 million in the first quarter of 2009. The 2010 results also include a $0.6 million after-tax charge associated with the 2010 Healthcare Act.

NU Parent and Other Companies: NU parent and other companies recorded net expenses of $4.1 million, or $0.02 per share, in the first quarter of 2010, compared with net expenses of $2.7 million, or $0.02 per share, in the first quarter of 2009. The lower results were due primarily to a $0.6 million after-tax charge associated with the 2010 Healthcare Act, a $0.6 million after-tax environmental reserve increase related to additional estimated costs of tar delineation and site characterization studies at an HWP coal tar remediation site, and the absence in 2010 of a $0.7 million favorable tax audit settlement.

Future Outlook

EPS Guidance: A summary of our projected 2010 EPS by business, which also reconciles consolidated fully diluted EPS to the non-GAAP financial measure of EPS by business, is reaffirmed as follows:


	2010 EPS Range
(Approximate amounts)		Low		High
Fully Diluted EPS (GAAP)	$	1.80	$	2.00

Regulated companies:
Distribution segment	$	0.95	$	1.05
Transmission segment		0.90		0.95
Total Regulated companies		1.85		2.00
Competitive businesses		-		0.05
NU parent and other companies		(0.05)		(0.05)
Fully Diluted EPS (GAAP)	$	1.80	$	2.00

The reaffirmed earnings guidance above takes into consideration the impacts of the first quarter 2010 retail electric and firm natural gas sales decrease as well as the first quarter and full year 2010 income tax impacts of the 2010 Healthcare Act. We have also included estimated impacts from current economic conditions in the assumptions that were used to develop our earnings guidance. The 2010 distribution segment guidance reflects an assumed one percent annual decrease in total weather normalized retail electric sales, a decrease in Yankee Gas' annual uncollectibles expense, and uncertainty around the outcomes of the PSNH distribution rate case that was filed in June 2009 and the CL&P distribution rate case filed in January 2010. Outcomes in both the PSNH and CL&P rate cases are expected in mid-2010.

A WMECO distribution rate case is expected to be filed in mid-2010 with a decision expected by early 2011. A Yankee Gas rate case is also being considered for filing no earlier than January 1, 2011. Neither rate case filing will impact 2010 results.

Long-Term Growth Rate: We continue to project that we will achieve a compound average annual EPS growth rate for the five-year period from 2010 to 2014 of between 6 percent and 9 percent using 2009 EPS of $1.91 as the base level. This EPS growth rate assumes regulatory ROEs averaging approximately 12.25 percent for the transmission segment and an average of approximately 10 percent for the distribution segment (including PSNH and WMECO generation). We believe this growth will be achieved if our capital program is completed in accordance with our plans, distribution rate case orders enable us to earn the assumed level of regulatory ROEs, and FERC's current transmission policies remain consistent and enable us to achieve projected transmission ROEs. In addition to the assumptions above, there are certain items that will likely impact this earnings growth rate. These items include, but are not limited to, sales levels; operating expense levels, including maintenance, pension and uncollectibles expense; and lower margins that NU Enterprises expects to earn on Select Energy’s remaining contracts.

Liquidity

Consolidated: We had $30 million of cash and cash equivalents as of March 31, 2010, compared with $27 million as of December 31, 2009.

On March 8, 2010, WMECO issued $95 million of senior unsecured notes with a coupon rate of 5.1 percent and a maturity date of March 1, 2020.

On April 1, 2010, CL&P remarketed $62 million of tax-exempt PCRBs that were subject to a mandatory tender on April 1, 2010. The PCRBs, which mature on May 1, 2031, carry a coupon rate of 1.4 percent and have a mandatory tender on April 1, 2011, at which time CL&P expects to remarket the bonds.

On April 22, 2010, Yankee Gas issued $50 million of privately placed first mortgage bonds with a coupon rate of 4.87 percent and a maturity date of April 1, 2020.

The proceeds from the above completed financings were used to repay short-term borrowings incurred in the ordinary course of business and to fund ongoing capital investment programs. We anticipate no additional long-term debt issuances in 2010.

We had cash flows provided by operating activities in the first quarter of 2010 of $159.1 million, compared with operating cash flows of $77.5 million in the first quarter of 2009 (all amounts are net of RRB payments, which are included in financing activities on the

accompanying unaudited condensed consolidated statements of cash flows). The improved cash flows were due primarily to the absence in 2010 of costs at PSNH and WMECO related to the major storm in December 2008 that were paid to vendors in the first quarter of 2009, the absence in the first quarter of 2010 of monthly PBOP contributions for the January 2010 to March 2010 periods for which a cumulative contribution of $10.3 million was made in April 2010 (monthly contributions were made in 2009), and an increase in cash flow benefits from accounts payable related to the February and March 2010 unpaid major storm costs impacting both CL&P and PSNH. Offsetting these favorable cash flow impacts was an increase in income tax payments largely attributable to the absence of bonus depreciation tax deductions under the American Recovery and Reinvestment Act of 2009 in the first quarter of 2010. Bonus depreciation tax deductions expired at the end of 2009.

We project consolidated cash flows provided by operating activities of approximately $650 million in 2010, net of RRB payments, which is $50 million lower than our previous projections due primarily to the 2010 severe storm costs. The projection for 2010 operating cash flows reflects a cash contribution to our Pension Plan in the third quarter of 2010 of approximately $45 million, the majority of which will be funded by PSNH. This contribution will be the first contribution to our Pension Plan in approximately 20 years.

A summary of the current credit ratings and outlooks by Moody's, S&P and Fitch for senior unsecured debt of NU parent and WMECO and senior secured debt of CL&P and PSNH is as follows:

Moody's

S&P

Fitch

Current

Outlook

Current

Outlook

Current

Outlook

NU parent

Baa2

Stable

BBB-

Stable

BBB

Stable

CL&P

Stable

BBB+

Stable

A-

Stable

PSNH

Stable

BBB+

Stable

BBB+

Stable

WMECO

Baa2

Stable

BBB

Stable

BBB+

Stable

If NU parent's senior unsecured debt ratings were to be reduced to below investment grade level by either Moody's or S&P, a number of Select Energy's supply contracts would require Select Energy to post additional collateral in the form of cash or LOCs. If such an event had occurred as of March 31, 2010, Select Energy, under its remaining contracts, would have been required to provide additional cash or LOCs in an aggregate amount of $29 million to various unaffiliated counterparties and additional cash or LOCs in the aggregate amount of $8.6 million to independent system operators. NU parent would have been and remains able to provide that collateral on behalf of Select Energy.

If unsecured debt ratings for PSNH were to be reduced by either Moody's or S&P, certain supply contracts could require PSNH to post additional collateral in the form of cash or LOCs with various unaffiliated counterparties. If PSNH's unsecured debt ratings had been reduced by one level, PSNH would not have been required to post additional collateral as of March 31, 2010. If these ratings had been reduced by two levels, or below investment grade, the amount of additional collateral required to be posted by PSNH would have been $6.5 million as of March 31, 2010. PSNH would have been and remains able to provide these collateral amounts.

We paid common dividends of $45.1 million in the first quarter of 2010, compared with $37.2 million in the first quarter of 2009. The increase reflects a 7.9 percent increase in our common dividend rate that took effect in the first quarter of 2010, as well as a higher number of shares outstanding as a result of the March 2009 equity issuance. On April 13, 2010, our Board of Trustees declared a quarterly common dividend of $0.25625 per share, payable on June 30, 2010 to shareholders of record as of June 1, 2010.

In general, the Regulated companies pay approximately 60 percent of their earnings to NU parent in the form of common dividends. In the first quarter of 2010, CL&P, PSNH, WMECO, and Yankee Gas paid $35.8 million, $12.6 million, $3.7 million, and $18.8 million, respectively, in common dividends to NU parent. In the first quarter of 2010, NU parent made equity contributions of $23.5 million and $66.1 million to PSNH and WMECO, respectively, and no contributions to CL&P and Yankee Gas.

Cash capital expenditures included on the accompanying unaudited condensed consolidated statements of cash flows and described in this "Liquidity" section do not include amounts incurred on capital projects but not yet paid, cost of removal, AFUDC related to equity funds, and the capitalized portions of pension and PBOP expense or income. A summary of our cash capital expenditures by company for the first quarters of 2010 and 2009 is as follows:


	For the Three Months Ended March 31,
(Millions of Dollars)		2010		2009
CL&P	$	97.7	$	116.3
PSNH		54.1		52.5
WMECO		19.1		19.2
Yankee Gas		12.9		13.4
Other		18.7		7.5
Totals	$	202.5	$	208.9

The decrease in our cash capital expenditures was the result of lower distribution segment capital expenditures of $13.4 million, particularly at CL&P, offset by an increase in Other of $11.2 million primarily related to capital costs at NUSCO, one of our corporate service companies.

As a result of LBCB's refusal in 2008 to continue to fund its commitment of approximately $56 million under our revolving credit agreements, our aggregate borrowing capacity under those credit facilities was reduced from $900 million to $844 million. This borrowing capacity, when combined with our access to other funding sources, provides us with adequate liquidity.

NU parent’s revolving credit agreement, in a nominal aggregate amount of $500 million, $482.3 million excluding the commitment of LBCB, expires on November 6, 2010. As of March 31, 2010, NU parent had $49.6 million of LOCs issued for the benefit of certain subsidiaries (primarily PSNH) and $100.3 million of borrowings outstanding under this facility. The weighted-average interest rate on these short-term borrowings as of March 31, 2010 was 0.625 percent, which is based on a variable rate plus an applicable margin based on NU parent's credit ratings. NU parent had $332.3 million of borrowing availability on this facility as of March 31, 2010, excluding LBCB's commitment, as compared to $341 million of availability as of December 31, 2009.

The Regulated companies maintain a joint revolving credit agreement in a nominal aggregate amount of $400 million, $361.8 million excluding the commitment of LBCB, which also expires on November 6, 2010. There were no borrowings outstanding under this facility as of March 31, 2010. The Regulated companies had $361.8 million of aggregate borrowing availability on this facility as of March 31, 2010 and December 31, 2009, excluding LBCB's commitment and subject to each individual company's borrowing limits.

Impact of Financial Market Conditions: While the impact of continued financial market volatility and the extent and impacts of the economic environment cannot be predicted, we are confident that we currently have operating flexibility and access to funding sources to maintain adequate liquidity. The credit outlooks for NU parent and its Regulated companies are all stable. Our companies have a low risk of calls for collateral due to our business model, and we have no long-term debt maturing until April 2012. An estimated cash contribution to our Pension Plan of approximately $45 million is expected to be made in the third quarter of 2010, and we continue to project capital expenditures for 2010 of approximately $1.1 billion.

We expect to renew our revolving credit agreements before their November 6, 2010 expiration dates and costs associated with the new facilities will be higher than those associated with the existing revolving credit agreements due to changes in credit market conditions.

Business Development and Capital Expenditures

Consolidated: Our consolidated capital expenditures, including amounts incurred but not paid, cost of removal, AFUDC, and the capitalized portions of pension and PBOP expense or income (all of which are non-cash factors), totaled $182.7 million in the first quarter of 2010, compared with $183 million in the first quarter of 2009. These amounts included $12.5 million and $4.4 million in the first quarters of 2010 and 2009, respectively, related to our corporate service companies.

Regulated Companies: Capital expenditures for the Regulated companies are expected to total approximately $1.1 billion ($441 million for CL&P) in 2010, which includes planned spending of approximately $48 million for our corporate service companies.

Transmission Segment: Transmission segment capital expenditures decreased by $5.8 million in the first quarter of 2010, as compared with the same period in 2009, due primarily to reductions in expenditures at CL&P and PSNH, partially offset by increases at WMECO and capital expenditures incurred for the Northern Pass project. A summary of transmission segment capital expenditures by company in the first quarters of 2010 and 2009 is as follows:


	For the Three Months Ended March 31,
(Millions of Dollars)		2010		2009
CL&P	$	28.2	$	36.4
PSNH		7.1		9.9
WMECO		15.4		10.9
Northern Pass project costs*		0.8		-
Totals	$	51.5	$	57.2

Since the inception of the Northern Pass project, we have incurred a total of $2.5 million in costs, $1.7 million of which was recognized in 2009.

In October 2008, CL&P and WMECO made state siting filings in Connecticut and Massachusetts, respectively, for the first and largest component of our NEEWS project, the GSRP. In October 2009, ISO-NE affirmed the need and need date for GSRP. On March 16, 2010, the CSC approved the 12-mile section of GSRP that CL&P plans to build in Connecticut. The CSC approval did not significantly change the project as it was originally proposed and is not expected to have a material impact on the overall cost of GSRP. Hearings on the 23-mile Massachusetts portion before the state’s EFSB were completed in February 2010, and briefs were filed by the parties on March 26, 2010. We expect to receive a final EFSB decision in the third quarter of 2010. GSRP, which involves the construction of 115 KV and 345 KV lines from Ludlow, Massachusetts to Bloomfield, Connecticut, is the largest and most complicated project within NEEWS, and is expected to cost $714 million if built according to our preferred route configuration. Following decisions from the state siting boards and receipt of other required permits, we expect to commence construction in late 2010 or early 2011 and to place the project in service in 2013.

Our second major NEEWS project is the Interstate Reliability Project, which is being designed and built in coordination with National Grid USA. CL&P's share of this project includes an approximately 40-mile, 345 KV line from Lebanon, Connecticut to the Connecticut-Rhode Island border where it would connect with enhancements National Grid USA is designing. We currently expect that CL&P's share of the costs of this project will be $250 million. Municipal consultations concluded in November 2008, and CL&P plans to file its

siting application with Connecticut regulators in early 2011 following the completion of ISO-NE’s reassessment of the need date and issuance of its regional system plan. We currently expect the project to be placed in service in late 2014.

The third major part of NEEWS is the Central Connecticut Reliability Project, which involves construction of a new line from Bloomfield, Connecticut to Watertown, Connecticut. This line would provide another 345 KV connection to move power across the state of Connecticut. The timing of this project would be six to twelve months behind the Interstate Reliability Project. This project is currently expected to cost $315 million.

ISO-NE is currently performing an evaluation of all projects in its regional system plan, including the other components of NEEWS, and assessing the presently estimated need dates for these projects. We expect ISO-NE’s view on need dates for the second and third major NEEWS projects to be updated in the next version of the regional system plan, a draft of which we expect to see during the third quarter of 2010.

Included as part of NEEWS are $211 million of associated reliability related expenditures for projects, of which over $50 million are moving forward through the siting and construction phases and are expected to be completed in advance of the three major projects. On March 19, 2010, the DPU approved a $23 million project from West Springfield to Agawam, Massachusetts. We expect to commence work on this project later this year and complete it in 2011.

We currently expect that CL&P's and WMECO's total capital expenditures for NEEWS will be $1.49 billion. Our current capital expenditure and rate base forecasts assume that all NEEWS projects are completed by the end of 2014. However, the timing and amount of our projected annual capital spending could be affected if receipt of siting approvals is delayed or if the need dates for these projects change through ISO-NE's regional system planning process. During the siting approval process, state regulators may require changes in configuration (including placing some lines underground) to address local concerns that could increase construction costs. Our current design for NEEWS does not contemplate any underground lines. Building any lines underground, particularly 345 KV lines, would increase total costs of the project beyond those reflected above. Since inception of NEEWS through March 31, 2010, CL&P and WMECO have capitalized approximately $75.1 million and $82.5 million, respectively, in costs associated with NEEWS, of which $7.6 million and $8.2 million, respectively, were capitalized in the first quarter of 2010.

NU, through a newly-formed holding company, NUTV, and NSTAR Transmission Ventures, Inc., a subsidiary of NSTAR, jointly formed a limited liability company, NPT, to construct, own and operate the Northern Pass line, a new HVDC transmission line from Canada to New Hampshire that will interconnect with a transmission line being developed by HQ-Trans-Energie, the transmission affiliate of Hydro-Québec. Pursuant to NPT’s operating agreement, NUTV holds a 75 percent interest in NPT with NSTAR holding the remaining 25 percent. Under the proposed arrangement with HQ, NPT would sell to HQ or its subsidiary 1,200 MW of firm electric transmission service over the Northern Pass line in order for HQ to sell and deliver this same amount of electric power from low-carbon energy resources to New England.

We continue to make progress in the design of the Northern Pass line. We have reached conceptual agreement in the development of a Transmission Service Agreement (TSA) with HQ. The TSA will be subject to FERC approval and will establish risk allocation and cost recovery for the project. We are continuing our early engineering work on the line and we will begin significant public communications and outreach efforts in the New Hampshire communities where new facilities are expected to be located. We expect to file the project design with ISO-NE for technical review and the TSA with the FERC by mid-2010. There are a number of additional state and federal permits that will be required to site the Northern Pass project line and we anticipate we will begin the process of filing those applications in 2010. We currently expect to begin construction of the line in late 2012 and have power flowing in 2015. We continue to expect our share of this project to cost $675 million.

In addition, the NU Regulated companies and NSTAR are continuing to negotiate one or more long-term power purchase agreements with HQ for power transmitted over the Northern Pass line. Our intention is to create a power purchase agreement structure that could be offered to other load serving entities in addition to NU and NSTAR. Power purchase agreement terms will be subject to state regulatory approvals. We anticipate filing these power purchase agreements subsequent to the TSA.

Distribution Segment: Distribution segment capital expenditures decreased by $2.7 million in the first quarter of 2010, as compared with the same period in 2009. A summary of distribution segment capital expenditures by company for the first quarters of 2010 and 2009 is as follows:


		For the Three Months Ended March 31,
(Millions of Dollars)		2010		2009
CL&P	$	57.3	$	65.4
PSNH		14.4		18.4
WMECO		5.3		6.9
Totals - Electric distribution (excluding generation)		77.0		90.7
Yankee Gas		7.0		10.2
Other		-		0.1
Total distribution		84.0		101.0
PSNH generation		34.7		20.4
Total distribution segment	$	118.7	$	121.4

PSNH's Clean Air Project is a $457 million wet scrubber project at its Merrimack coal station, the cost of which will be recovered through PSNH's ES rates under New Hampshire law. Construction is expected to be under budget and completed in mid-2012. Since inception of the project, PSNH has capitalized $178.8 million associated with this project, of which $32 million was capitalized in the first quarter of 2010. Construction of the project was approximately 51 percent complete as of March 31, 2010.

In April 2010, Yankee Gas commenced its WWL Project, the construction of a 16-mile gas pipeline between Waterbury and Wallingford, Connecticut and the increase of vaporization output of its LNG plant. Since inception of the project, Yankee Gas has capitalized $1.2 million associated with this project, $0.4 million of which was capitalized in the first quarter of 2010.

Strategic Initiatives: We continue to evaluate certain development projects that will benefit our customers, which are detailed below.

Over the past two years, we have participated in discussions with other utilities, policymakers, and prospective developers of renewable energy projects in the New England region regarding a framework whereby renewable power projects built in rural areas of northern New England could be connected to the electric load centers of New England. We believe there are significant opportunities for developers to build wind and biomass projects in northern New England that could help the region meet its renewable portfolio standards. We believe that a collaborative approach among project developers and transmission owners is necessary to be able to construct needed projects and bring their electrical output into the market. To date, most discussions have been conceptual in nature and therefore we have not yet included any capital expenditures associated with potential projects in our five-year capital program.

On March 31, 2010, CL&P filed with the DPUC an AMI and dynamic pricing plan that included a cost benefit analysis. CL&P concluded that a full deployment of AMI meters accompanied by dynamic pricing options for all CL&P customers would be cost beneficial under a set of reasonable assumptions, identified as the "base case scenario." Under the base case scenario, capital expenditures associated with the installation of the meters are estimated at $296 million, which amount is not included in our five-year capital expenditure projections. Under CL&P's proposal, installation of meters is proposed to begin in late 2012 and continue through 2016. CL&P proposes to file by mid-2012 with the DPUC a detailed implementation plan that includes results of an RFP to select deployment vendors, reflects industry AMI standards that are under development, and presents a full timeline for the rollout of AMI meters and dynamic pricings.

On October 16, 2009, WMECO filed its proposal for a dynamic pricing smart meter pilot program with the DPU. The program proposes to involve 1,750 customers in WMECO's service region for a term of six months beginning in April 2011. The total cost of the project is estimated to be $7 million, which would be recovered through rates WMECO would charge to customers taking Basic Service. A decision is expected from the DPU by August 1, 2010.

On August 12, 2009, the DPU approved a stipulation agreement between WMECO and the Massachusetts Attorney General concerning WMECO's proposal, under the Massachusetts Green Communities Act, to install 6 MW of solar energy generation in its service territory at an estimated cost of $41 million. On February 17, 2010, WMECO announced that it planned to install 1.8 MW of the 6 MW at a site in Pittsfield, Massachusetts. That project is expected to cost between $10 million to $12 million.

Transmission Rate Matters

Transmission - Wholesale Rates: NU's transmission rates recover total transmission revenue requirements, ensuring that we recover all regional and local revenue requirements. These rates provide for annual true-ups to actual costs. The financial impacts of differences between actual and projected costs are deferred for future recovery from or refund to customers. As of March 31, 2010, NU was in a total underrecovery position of $41.5 million ($29 million for CL&P) of which $38.8 million ($28.2 million for CL&P) will be collected from customers in June 2010.

Legislative Matters

2010 Federal Legislation: On March 23, 2010, President Obama signed into law the 2010 Healthcare Act, which includes a provision that eliminated the tax deductibility of certain PBOP contributions equal to the amount of the federal subsidy received by companies like NU, which sponsor retiree health care benefit plans with a prescription drug benefit that is actuarially equivalent to Medicare Part D. As a result of the 2010 Healthcare Act, for the three months ended March 31, 2010, we recorded a net after-tax charge of $3 million in the accompanying unaudited condensed consolidated statement of income. As a result of the elimination of the tax deduction in 2010, NU will not be able to recognize approximately $2 million of current period benefits. Therefore, NU's projected 2010 effective tax rate, including these discrete items expected to occur during 2010, is estimated to be approximately 38 percent. Excluding the impacts of discrete items, NU's 2010 effective tax rate would be estimated to be approximately 36 percent.

2010 Connecticut Legislation: On May 5, 2010, the Connecticut Legislature passed senate bill 493, which, if it becomes law, would reorganize the DPUC, launch a significant solar generation initiative, allow distribution companies to manage a portfolio that would provide some of their standard service supply and implement reduced distribution rates for low-income customers. While we do not believe that the bill will have an adverse financial impact on us, we are concerned that certain elements, particularly the solar mandate, would increase customer prices.

In addition, the Connecticut Legislature approved a state budget for the 2010-2011 fiscal year, which calls for the issuance of $956 million of economic recovery revenue bonds that would be amortized over eight years. These bonds would be repaid through a charge on customer bills of CL&P and other Connecticut utilities. For CL&P, the revenue to pay interest and principal on the bonds would come from a continuation of a portion of its CTA, which would otherwise end at the end of this year, and the diversion of about one-third

of the annual funding for C&LM programs beginning in 2012. The specifics of these adjustments will be determined by the DPUC. On average, we believe that the CL&P portion to support these bonds would be about $108 million annually.

Regulatory Developments and Rate Matters

2010 Major Storms: In the first quarter of 2010, severe storms struck portions of the Northeast region damaging the distribution systems and causing extensive power outages in both CL&P’s and PSNH’s service territories. On February 25, 2010, a severe storm with high winds caused nearly 270,000 PSNH customers to lose power. Restoration was completed by March 3, 2010. PSNH estimates that the cost of restoration was approximately $24 million. On March 13, 2010, another severe storm with high winds caused widespread damage to CL&P’s overhead facilities in southwest Connecticut, and caused 160,000 CL&P customers to lose power. CL&P estimates that the cost of restoration was approximately $21 million. Both CL&P and PSNH expect the costs associated with these major storms will be recoverable through a combination of insurance proceeds, customer-funded reserves that are established for the purpose of recovering major storm costs, and current distribution revenues. On March 17, 2010, the DPUC opened a docket to investigate the restoration efforts of CL&P and UI following the outages. We do not expect the outcome of the DPUC’s investigation to have a material adverse impact on CL&P’s earnings, financial position, or cash flows.

Connecticut - CL&P:

Distribution Rates: On January 8, 2010, CL&P filed an application with the DPUC to raise distribution rates by $133.4 million, or 3.4 percent over current revenues, to be effective July 1, 2010, and by an additional $44.2 million, or 1.1 percent over current revenues, to be effective July 1, 2011. Among other items, CL&P is seeking an increase in its authorized ROE from the current 9.4 percent to 10.5 percent. CL&P proposed that the first year’s increase be deferred until January 1, 2011 and that approximately $67 million of cash revenue requirements for the second half of 2010 be deferred and recovered from CL&P customers between January 1, 2011 and June 30, 2012. If approved by the DPUC, an annualized $210 million increase in distribution rates would take effect on January 1, 2011. CL&P expects that as a result of a decline in stranded cost recoveries due to the final amortization of CL&P’s RRBs in December 2010, CL&P’s CTA will decline by approximately $230 million on an annualized basis on January 1, 2011, more than offsetting the impact of the distribution rate increase. Hearings before the DPUC were completed and final briefs were filed in April 2010. A final decision is expected in June 2010.

Standard Service and Last Resort Service Rates: CL&P's residential and small commercial customers who do not choose competitive suppliers are served under SS rates, and large commercial and industrial customers who do not choose competitive suppliers are served under LRS rates. Effective January 1, 2010, the DPUC approved a decrease to CL&P’s total average SS rates of approximately 4.6 percent. The energy supply portion of the total average SS rate decreased from 12.516 cents per KWh to 11.289 cents per KWh. Effective April 1, 2010, the DPUC approved a decrease to CL&P’s total average LRS rate of approximately 11.3 percent. The energy supply portion of the total average LRS rate decreased from 9.662 cents per KWh to 8.055 cents per KWh. CL&P is fully recovering from customers the costs of its SS and LRS services.

CTA and SBC Reconciliation: On March 31, 2010, CL&P filed with the DPUC its 2009 CTA and SBC reconciliation, which compared CTA and SBC revenues charged to customers to revenue requirements and allows for full recovery of revenue requirements. For the 12 months ended December 31, 2009, total CTA revenue requirements exceeded CTA revenues by $46.9 million, which was recorded as an increase to Regulatory assets on the accompanying unaudited condensed consolidated balance sheet. For the 12 months ended December 31, 2009, the SBC revenues exceeded SBC revenue requirements by $23.7 million, which was recorded as a decrease to Regulatory assets on the accompanying unaudited condensed consolidated balance sheet. We expect a decision in this docket from the DPUC by the end of 2010 and do not expect the outcome to have a material adverse impact on CL&P’s earnings, financial position or cash flows.

Procurement Fee Rate Proceedings: In prior years, CL&P submitted to the DPUC its proposed methodology to calculate the variable

incentive portion of its transition service procurement fee, which was effective for the years 2004, 2005 and 2006, and requested approval of the pre-tax $5.8 million 2004 incentive fee. CL&P has not recorded amounts related to the 2005 or 2006 procurement fee in earnings. CL&P recovered the $5.8 million pre-tax amount, which was recorded in 2005 earnings, through the CTA reconciliation process. On January 15, 2009, the DPUC issued a final decision in this docket reversing its December 2005 draft decision and stated that CL&P was not eligible for the procurement incentive compensation for 2004. A $5.8 million pre-tax charge (approximately $3.5 million net of tax) was recorded in the 2008 earnings of CL&P, and an obligation to refund the $5.8 million to customers was established as of December 31, 2008. CL&P filed an appeal of this decision on February 26, 2009. On February 4, 2010, the Connecticut Superior Court reversed the DPUC decision. The Court remanded the case back to the DPUC for the correction of several specific errors. On February 22, 2010, the DPUC appealed the Connecticut Superior Court's February 4, 2010 decision to the Connecticut Appellate Court. A procedural schedule has not been finalized for the DPUC's appeal to the Appellate Court.

New Hampshire:

Merrimack Clean Air Project: On July 7, 2009, the New Hampshire Site Evaluation Committee determined that PSNH’s Clean Air Project to install wet scrubber technology at its Merrimack Station was not subject to the Committee’s review as a "sizeable" addition to a power plant under state law. That Committee upheld its decision in an order dated January 15, 2010, denying requests for rehearing. This order was appealed on February 23, 2010. On April 15, 2010, the New Hampshire Supreme Court determined that it would accept the appeal, but has not established a procedural schedule for the appeal. We do not believe that the appeal will have a material impact on the timing or costs of the project. PSNH is continuing with construction of this project and has capitalized $178.8 million since inception of the project through March 31, 2010 as of which date construction was approximately 51 percent complete.

Distribution Rates: The NHPUC issued an order on July 31, 2009 approving a temporary increase of $25.6 million in PSNH’s distribution rates on an annualized basis, effective August 1, 2009. Included in the $25.6 million temporary increase is $6 million to begin the recovery of PSNH's approximately $49 million deferral of storm costs incurred in December 2008.

On June 30, 2009, PSNH filed an application with the NHPUC requesting a permanent increase in distribution rates of approximately $51 million on an annualized basis to be effective August 1, 2009, and another $17 million to be effective July 1, 2010. On April 30, 2010, PSNH, the NHPUC staff and the Office of Consumer Advocate submitted a proposed settlement of the rate case PSNH had filed on June 30, 2009 with the NHPUC. Under the proposed settlement, the settling parties agreed to a net distribution rate increase of $45.5 million on an annualized basis to be effective July 1, 2010, and annualized distribution rate adjustments projected at negative $2.9 million, and positive $9.5 million and $11.1 million on July 1 of each of the three subsequent years, respectively. The $45.5 million increase is in addition to the $25.6 million temporary increase that became effective August 1, 2009. The $45.5 million increase includes $13.7 million to reconcile the difference between the temporary rates and the permanent rates back to August 1, 2009. The projected decrease of $2.9 million on July 1, 2011 reflects primarily the end of the recoupment of the $13.7 million reconciliation on that date. PSNH also agreed not to file a new distribution rate case until June 30, 2015. During the term of the settlement, PSNH’s ability to propose changes to its permanent distribution rate level will be limited to situations where its 12-month distribution ROE falls below 7 percent for two consecutive quarters or certain specified external events occur, as defined in the settlement. Another provision of the settlement was that the authorized regulatory ROE on distribution only plant continues at the previously allowed level of 9.67 percent. A decision by the NHPUC is expected in June 2010. Any differences between allowed temporary rates and permanent rates will be reconciled back to August 1, 2009.

ES and SCRC Reconciliation: On an annual basis, PSNH files with the NHPUC an ES/SCRC reconciliation filing for the preceding year. On April 30, 2010, PSNH filed its 2009 ES/SCRC reconciliation with the NHPUC, whose evaluation includes a prudence review of PSNH's generation activities. During 2009 ES costs exceeded ES revenues by $45.9 million, as a result of refunding the 2008 ES regulatory obligation to customers through a lower ES rate. During 2009, SCRC revenues exceeded SCRC costs by $6.4 million. As of December 31, 2009 PSNH had an ES regulatory asset and a SCRC regulatory asset of $4.4 million and $3.9 million, respectively, for costs that are included in the 2010 ES/SCRC rate calculations for recovery from customers. We do not expect the outcome of the NHPUC review to have a material adverse impact on PSNH’s earnings, financial position or cash flows.

Massachusetts:

Customer Rates: WMECO intends to file a distribution rate case in mid-2010 to be effective in early 2011, which will be preceded by a letter of intent. The distribution rate case will include a proposal, as required by the DPU, to fully decouple distribution revenues from KWh sales.

Basic Service Rates: Effective January 1, 2010, the rates for all basic service customers changed to reflect the basic service solicitations conducted by WMECO in November 2009. Basic service rates for residential customers decreased to 8.257 cents per KWh, rates for small commercial and industrial customers decreased to 8.992 cents per KWh. Effective April 1, 2010, the basic service rate for medium and large commercial and industrial customers decreased to 8.528 cents per KWh to reflect the basic service solicitation conducted by WMECO in February 2010.

Pension Factor Reconciliation Filing: On July 2, 2009, WMECO filed the 2008 reconciliation for its pension factor revenues and expenses. An evidentiary hearing was held on March 26, 2010 and briefs will be filed in May 2010. There is no date set for when the DPU will render its final decision. We do not expect the outcome of the DPU's review of this filing to have a material adverse impact on WMECO's earnings, financial position or cash flows.

NU Enterprises Divestitures

We have exited most of our competitive businesses. NU Enterprises continues to manage to completion its remaining wholesale marketing contracts and to manage its electrical contracting business.

Off-Balance Sheet Arrangements

Letters of Credit: NU parent provides standby LOCs for the benefit of its subsidiaries under its revolving credit agreement. PSNH posts such LOCs as collateral with counterparties and ISO-NE. As of March 31, 2010, PSNH had posted $47.6 million in such NU parent LOCs, which includes $10 million with ISO-NE. In addition, Select Energy had posted $2 million NU parent LOCs with ISO-NE as of March 31, 2010.

Competitive Businesses: We have various guarantees and indemnification obligations outstanding on behalf of former subsidiaries in connection with the exit from our competitive businesses. See Note 4B, "Commitments and Contingencies - Guarantees and Indemnifications," to the unaudited condensed consolidated financial statements for information regarding the maximum exposure and amounts recorded under these guarantees and indemnification obligations.

Critical Accounting Policies and Estimates Update

The preparation of financial statements in conformity with GAAP requires management to make estimates, assumptions and at times difficult, subjective or complex judgments. Changes in these estimates, assumptions and judgments, in and of themselves, could

materially impact our financial position, results of operations or cash flows. Our management communicates to and discusses with our Audit Committee of the Board of Trustees all critical accounting policies and estimates. The accounting policies and estimates that we believed were the most critical in nature were reported in our 2009 Form 10-K. There have been no material changes with regard to these critical accounting policies and estimates.

Other Matters

Contractual Obligations and Commercial Commitments: There have been no additional contractual obligations identified and no material changes with regard to the contractual obligations and commercial commitments previously disclosed in our 2009 Form 10-K.

Web Site: Additional financial information is available through our web site at www.nu.com.

RESULTS OF OPERATIONS – NORTHEAST UTILITIES AND SUBSIDIARIES

The following table provides the variances in income statement line items for the unaudited condensed consolidated statements of income for NU included in this Quarterly Report on Form 10-Q for the three months ended March 31, 2010:


	Income Statement Variances (Millions of Dollars) 2010 over/(under) 2009
	Amount		Percent
Operating Revenues	$	(254)	(16)	%

Operating Expenses:
Fuel, purchased and net interchange power		(236)	(28)
Other operating expenses		1	-
Maintenance		(3)	(7)
Depreciation		2	2
Amortization of regulatory (liabilities)/assets, net		(30)	(a)
Amortization of rate reduction bonds		4	7
Taxes other than income taxes		(1)	(1)
Total operating expenses		(263)	(19)

Operating Income		9	4

Interest expense		(4)	(5)
Other income, net		4	93
Income before income tax expense		17	11
Income tax expense		28	55
Net income		(11)	(12)
Preferred dividends of subsidiary		-	-
Net income attributable to controlling interest	$	(11)	(12)	%

(a)

Percent greater than 100 not shown since not meaningful.

Comparison of the First Quarter of 2010 to the First Quarter of 2009

Operating Revenues


	For the Three Months Ended March 31,
(Millions of Dollars)	2010		2009		Variance
Electric distribution	$	1,000	$	1,246	$	(246)
Gas distribution		172		202		(30)
Total distribution		1,172		1,448		(276)
Transmission		153		134		19
Regulated companies		1,325		1,582		(257)
Competitive businesses		19		20		(1)
Other & eliminations		(5)		(9)		4
NU	$	1,339	$	1,593	$	(254)

Operating revenues decreased $254 million in 2010 due primarily to lower distribution revenues from the Regulated companies ($276 million) mainly as a result of the recovery of a lower level of electric and gas distribution fuel and other expenses passed through to customers through regulatory tracking mechanisms.

Electric distribution revenues decreased $246 million due primarily to a decrease in the portion of electric distribution revenues that does not impact earnings ($235 million) and a decrease in the component of revenues that impacts earnings ($11 million). The portion of electric distribution segment revenues that impacts earnings decreased $11 million due primarily to lower retail electric sales, partially offset by CL&P's rate changes effective in February 2009 and PSNH's rate changes effective in August 2009. Retail electric sales for the Regulated companies decreased 4.9 percent. Gas distribution revenues decreased $30 million due primarily to decreased recovery of fuel costs primarily as a result of lower sales volumes. Firm natural gas sales decreased 3.5 percent in the first quarter of 2010 compared with the same period of 2009.

The $235 million decrease in electric distribution revenues that does not impact earnings consists of the portions of distribution revenues that are included in regulatory commission approved tracking mechanisms that recover certain incurred costs ($225 million) and revenues that are eliminated in consolidation of the Regulated companies ($10 million). The distribution revenue tracking components decreased $225 million due primarily to lower recovery of generation service and related congestion charges ($211 million) and lower CL&P delivery-related FMCC ($17 million). The tracking mechanisms allow for rates to be changed periodically with overcollections refunded to customers or undercollections to be recovered from customers in future periods.

Transmission segment revenues increased $19 million due primarily to the return on a higher transmission investment base and the return of higher overall expenses, which are tracked and result in a related increase in revenues, resulting from an increase in transmission plant, such as higher property taxes, depreciation and operation and maintenance expenses.

Fuel, Purchased and Net Interchange Power

Fuel, purchased and net interchange power expenses decreased $236 million in 2010 due primarily to lower costs at the Regulated companies ($242 million), partially offset by higher competitive business expenses ($6 million). Fuel and purchased power expense for the Regulated companies decreased at CL&P ($152 million) due to lower GSC supply costs and other purchased power costs, partially offset by an increase in deferred fuel costs, at PSNH ($42 million) due to an increased level of migration of ES customers to competitive electric supplier and lower retail sales, at Yankee Gas ($28 million) due to lower volumes in 2010 as compared to 2009, and at WMECO ($20 million) due to lower basic/default service supply costs. Competitive businesses’ expenses increased due to Select Energy mark-to-market losses in 2010 as a result of changes in power prices across the forward price curve, as compared to a gain in 2009 related to the remaining wholesale marketing contracts.

Other Operating Expenses

Other operating expenses increased $1 million in 2010 due primarily to higher NU parent and other companies expenses ($2 million) and higher Regulated companies' distribution and transmission segment expenses ($1 million), partially offset by lower competitive businesses' expenses ($2 million).

NU parent and other companies expenses were higher due primarily to an increase to environmental reserves at HWP Company ($1 million) and higher pension expense attributable to retirees at NAESCO. Competitive businesses' expenses were lower by $2 million due primarily to lower Boulos expenses as a result of a lower level of work. Higher Regulated companies' distribution and transmission segment expenses of $1 million were due primarily to higher electric distribution segment expenses ($5 million) including higher pension costs, and higher other operating costs ($4 million), partially offset by lower costs that are recovered through distribution tracking mechanisms that have no earnings impact ($9 million) such as customer services expenses and retail transmission.

Maintenance

Maintenance expenses decreased $3 million in 2010 due primarily to lower Regulated companies' distribution expenses ($5 million), partially offset by higher transmission line expenses ($2 million). Distribution expenses were lower due primarily to the timing of vegetation management work ($6 million), partially offset by higher repair and maintenance of distribution lines ($1 million).

Depreciation

Depreciation expenses increased $2 million in 2010 due primarily to higher transmission ($1 million) and distribution ($1 million) plant balances resulting from completed construction projects placed into service.

Amortization of Regulatory (Liabilities)/Assets, Net

Amortization of regulatory (liabilities)/assets, net decreased $30 million in 2010 primarily as a result of the impact of the 2010 Healthcare Act related to the write-off of previously recorded deferred tax assets that we believe are probable of recovery in future electric and natural gas distribution rates ($24 million).

Amortization of Rate Reduction Bonds

Amortization of RRBs expenses increased $4 million in 2010, which corresponded to the reduction in principal of the RRBs.

Taxes Other than Income Taxes

Taxes other than income taxes expenses decreased $1 million in 2010 due primarily to lower payroll related taxes.

Interest Expense

Interest expense decreased $4 million in 2010 due primarily to lower RRB interest resulting from lower principal balances outstanding ($4 million) and lower other interest ($1 million), partially offset by higher long-term debt interest ($2 million) resulting from the issuance of new long-term debt in 2009.

Other Income, Net

Other income, net increased $4 million in 2010 due primarily to the absence of investment losses recorded in 2009 and higher investment income due primarily to improved results from NU’s supplemental benefit trust ($5 million), and higher AFUDC equity income ($2 million) as a result of higher eligible CWIP balances and lower short-term debt, partially offset by lower CL&P Energy Independence Act incentives ($2 million).

Income Tax Expense

Income tax expense increased $28 million due primarily to the impacts of the 2010 Healthcare Act including $18 million from writing down deferred tax assets, $9 million as a result of establishing a 2010 Healthcare Act related regulatory asset and lower tax benefits for the three months ended March 31, 2010.

RESULTS OF OPERATIONS - THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES

The components of significant income statement variances, higher/(lower) in comparison to the previous year, are provided in the table below.


Income Statement Variances	2010 versus 2009
(Millions of Dollars)	Amount		Percent
Operating Revenues	$	(160)	(17)	%

Operating Expenses:
Fuel, purchased and net interchange power		(152)	(29)
Other operating expenses		(5)	(3)
Maintenance		(5)	(19)
Depreciation		1	2
Amortization of regulatory (liabilities)/assets, net		(11)	(87)
Amortization of rate reduction bonds		3	7
Taxes other than income taxes		(1)	(1)
Total operating expenses		(170)	(20)

Operating Income		10	9

Interest expense		1	2
Other income, net		2	82
Income before income tax expense		11	14
Income tax expense		16	59
Net Income	$	(5)	(9)	%

Comparison of the First Quarter of 2010 to the First Quarter of 2009

Operating Revenues

Operating revenues decreased $160 million in 2010 due to lower distribution segment revenues ($173 million), partially offset by higher transmission segment revenues ($13 million).

The distribution segment revenues decreased $173 million due primarily to a decrease in the portion of distribution revenues that does not impact earnings ($162 million). The portion of revenues that impacts earnings decreased $11 million primarily as a result of lower retail sales, partially offset by rate changes effective in February 2009. The 2010 retail sales as compared to the same period in 2009 decreased 4.9 percent.

The $162 million decrease in distribution segment revenues that do not impact earnings was due primarily to a decrease in the portions of retail revenues that are included in DPUC approved tracking mechanisms that track the recovery of certain incurred costs through CL&P's tariffs ($155 million) and transmission segment intracompany billings to the distribution segment that are eliminated in consolidation ($6 million). The distribution revenues included in DPUC approved tracking mechanisms decreased $155 million due primarily to a decrease in revenues associated with the recovery of GSC and supply-related FMCC ($138 million), and delivery-related FMCC ($17 million). The lower GSC and supply-related FMCC revenue was due primarily to lower retail sales, lower customer rates resulting from lower average supply prices and additional customer migration to third-party suppliers in 2010 as compared to 2009. The lower delivery-related FMCC revenue was due primarily to changes in projections for certain delivery-related FMCC costs for 2010 that significantly lowered the delivery-related FMCC rate in the first quarter of 2010 as compared to 2009. The tracking mechanisms allow for rates to be changed periodically with overcollections refunded to customers or undercollections to be recovered from customers in future periods.

Transmission segment revenues increased $13 million due primarily to the return on a higher transmission investment base and the return of higher overall expenses, which are tracked and result in a related increase in revenues, resulting from an increase in transmission plant such as higher property taxes, depreciation, and operation and maintenance expenses.

Fuel, Purchased and Net Interchange Power

Fuel, purchased and net interchange power expense decreased $152 million in 2010 due primarily to lower GSC supply costs ($169 million) and other purchased power costs ($6 million), partially offset by an increase in deferred fuel costs ($23 million), all of which are included in DPUC approved tracking mechanisms. The $169 million decrease in GSC supply costs was due primarily to lower retail sales, lower average supply prices, and additional customer migration to third-party suppliers in 2010 as compared to 2009. These GSC supply costs are the contractual amounts CL&P must pay to various suppliers that have been awarded the right to supply SS and LRS load through a competitive solicitation process. The $23 million increase in deferred fuel costs was due primarily to a smaller net underrecovery in the first quarter of 2010 as compared to 2009.

Other Operating Expenses

Other operating expenses decreased $5 million in 2010 as a result of lower costs that are recovered through distribution tracking mechanisms and have no earnings impact ($8 million) such as certain customer services expenses ($6 million), and retail transmission ($3 million), partially offset by higher distribution segment expenses ($3 million), including higher pension costs.

Maintenance

Maintenance expenses decreased $5 million in 2010 due primarily to lower repair and maintenance of distribution lines ($7 million), including lower storm expenses, partially offset by higher transmission segment expenses ($2 million). CL&P storm expenses incurred resulting from the March 2010 severe storm with high winds will be recovered through a combination of insurance proceeds, customer-funded reserves that are established for the purpose of recovering major storm costs, and current distribution revenues. These costs did not result in a significant maintenance variance when compared to storm costs incurred in the same period last year.

Depreciation

Depreciation expense increased $1 million in 2010 due primarily to higher utility plant balances resulting from completed construction projects placed into service.

Amortization of Regulatory (Liabilities)/Assets, Net

Amortization of regulatory (liabilities)/assets, net, decreased $11 million in 2010 primarily as a result of the impact of the 2010 Healthcare Act related to income taxes ($14 million), partially offset by higher amortization of the SBC balance ($3 million).

Amortization of Rate Reduction Bonds

Amortization of RRBs increased $3 million in 2010, which corresponded to the reduction in principal of the RRBs.

Taxes Other Than Income Taxes

Taxes other than income taxes decreased $1 million in 2010 due primarily to lower taxes paid in 2010 to the Town of Waterford for lost property tax revenue as a result of the sale of Millstone ($4 million), and lower payroll taxes ($1 million), partially offset by higher property taxes ($3 million), and higher gross earnings taxes ($1 million) recoverable in rates mainly as a result of higher transmission revenues that are subject to gross earnings tax.

Interest Expense

Interest expense increased $1 million in 2010 due primarily to higher long-term debt interest ($2 million) resulting from the $250 million debt issuance in February 2009, and other interest ($2 million) mostly related to the absence of the resolution of routine tax issues, partially offset by lower RRB interest resulting from lower principal balances outstanding ($3 million).

Other Income, Net

Other income, net, increased $2 million in 2010 due primarily to higher investment income due primarily to improved results from NU’s supplemental benefit trust and the absence of investment losses recorded in 2009 ($3 million), higher AFUDC equity income ($1 million) as a result of higher eligible CWIP balances and lower short-term debt and higher interest income ($1 million), partially offset by lower CL&P Energy Independence Act incentives ($2 million).

Income Tax Expense

Income tax expense increased $16 million in 2010 due primarily to the impacts of the 2010 Healthcare Act; including $9 million from writing down deferred tax assets, $6 million as a result of establishing the 2010 Healthcare Act related regulatory asset and lower tax benefits for the three months ended March 31, 2010.

LIQUIDITY

CL&P had cash flows provided by operating activities in the first quarter of 2010 of $73.2 million, compared with operating cash flows of $74.1 million in the first quarter of 2009 (amounts are net of RRB payments, which are included in financing activities). The slight decrease in cash flows was due primarily to an increase in income tax payments largely attributable to the absence of bonus depreciation tax deductions under the American Recovery and Reinvestment Act of 2009 in the first quarter of 2010. Bonus depreciation tax deductions expired at the end of 2009. Offsetting the tax payments was a decrease in payments made related to our accounts payable in support of our operating activities and our accounts payable related to the March 2010 unpaid major storm costs. We project cash flows provided by operating activities at CL&P of approximately $400 million in 2010, net of RRB payments, which is $40 million lower than our previous projections due primarily to recent CTA cost underrecoveries charge (which does not impact earnings) and the severe storm costs spent in 2010 to be recovered in future periods.

As of March 31, 2010, CL&P had no borrowings under the $400 million credit facility it shares with the other Regulated companies, under which it can borrow up to $200 million. Other financing activities for the three months ended March 31, 2010 included $35.8 million in common dividends paid to NU parent.

Cash capital expenditures included on the accompanying unaudited condensed consolidated statements of cash flows do not include amounts incurred on capital projects but not yet paid, cost of removal, the AFUDC related to equity funds, and the capitalized portions of pension and PBOP expense or income. CL&P's cash capital expenditures totaled $97.7 million for the three months ended March 31, 2010, compared with $116.3 million for the three months ended March 31, 2009. We project capital expenditures at CL&P of $441 million in 2010 (including non-cash factors).

RESULTS OF OPERATIONS - PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES

The components of significant income statement variances, higher/(lower) in comparison to the previous year, are provided in the table below.


Income Statement Variances	2010 versus 2009
(Millions of Dollars)	Amount		Percent
Operating Revenues	$	(49)	(16)	%

Operating Expenses:
Fuel, purchased and net interchange power		(42)	(29)
Other operating expenses		-	-
Maintenance		-	-
Depreciation		1	5
Amortization of regulatory (liabilities)/assets, net		(14)	(a)
Amortization of rate reduction bonds		1	6
Taxes other than income taxes		1	7
Total operating expenses		(53)	(19)

Operating Income		4	11

Interest expense		-	-
Other income, net		1	69
Income before income tax expense		5	20
Income tax expense		7	88
Net Income	$	(2)	(10)	%

(a)

Percent greater than 100 not shown since not meaningful.

Comparison of the First Quarter of 2010 to the First Quarter of 2009

Operating Revenues

Operating revenues decreased $49 million in 2010 due to lower distribution segment revenues ($52 million), partially offset by higher transmission segment revenues ($3 million).

The distribution segment revenues decreased $52 million due primarily to a decrease in the portion of distribution revenues that do not impact earnings ($54 million). The portion of revenues that impacts earnings increased $2 million primarily as a result of the retail rate increase effective in August 2009, partially offset by lower retail sales volumes. Retail sales decreased 5.3 percent in 2010 compared to the same period in 2009.

The $54 million decrease in the portion of distribution segment revenues that do not impact earnings was due primarily to a decrease in the portions of retail revenues that are included in NHPUC approved tracking mechanisms that track the recovery of certain incurred costs through PSNH’s tariffs ($52 million) and transmission segment intracompany billings to the distribution segment that are eliminated in consolidation ($2 million). The distribution revenues included in NHPUC approved tracking mechanisms decreased $52 million due primarily to lower recovery of purchased fuel and power costs ($54 million), lower Northern Wood Power Plant renewable energy certificate revenues ($3 million) and lower wholesale revenue ($1 million), partially offset by higher retail transmission revenues ($4 million) and an increase in the SCRC ($3 million). The tracking mechanisms allow for rates to be changed periodically with overcollections refunded to customers or undercollections to be recovered from customers in future periods.

Transmission segment revenues increased $3 million due primarily to the return on a higher transmission investment base and the return of higher overall expenses, which are tracked and result in a related increase in revenues, resulting from an increase in transmission plant such as higher property taxes, depreciation and operation and maintenance expenses.

Fuel, Purchased and Net Interchange Power

Fuel, purchased and net interchange power costs decreased $42 million in 2010 due primarily to an increased level of migration of ES customers to competitive electric suppliers and lower retail sales.

Depreciation

Depreciation expense increased $1 million in 2010 due primarily to higher utility plant balances resulting from completed construction projects placed into service in the transmission and distribution segments.

Amortization of Regulatory (Liabilities)/Assets, Net

Amortization of regulatory (liabilities)/assets, net expense decreased $14 million in 2010 due primarily to a decrease in net deferrals associated with the ES ($10 million) and SCRC ($1 million) tracking mechanisms and the impact of the 2010 Healthcare Act related to income taxes ($5 million), partially offset by an increase in net deferrals associated with the TCAM tracking mechanism ($2 million).

Amortization of Rate Reduction Bonds

Amortization of RRBs expense increased $1 million in 2010, which corresponded to the reduction in principal of the RRBs.

Taxes Other Than Income Taxes

Taxes other than income taxes expenses increased $1 million in 2010 due primarily to higher property taxes as a result of higher net plant balances and increased local municipal tax rates.

Other Income, Net

Other income, net, increased $1 million in 2010 due primarily to higher AFUDC equity income as a result of higher eligible CWIP balances and the absence of investment losses recorded in 2009 on NU's supplemental benefit trust.

Income Tax Expense

Income tax expense increased $7 million in 2010 due primarily to the impacts of the 2010 Healthcare Act; including $4 million from writing down deferred tax assets and $2 million as a result of establishing a 2010 Healthcare Act related regulatory asset.

LIQUIDITY

PSNH had cash flows provided by operating activities in the first quarter of 2010 of $60.7 million, compared with operating cash flows of $0.8 million in the first quarter of 2009 (amounts are net of RRB payments, which are included in financing activities). The improved cash flows were due primarily to the absence in 2010 of costs related to the major storm in December 2008 that were paid to vendors in the first quarter of 2009 and an increase in cash flow benefits from accounts payable related to the February 2010 unpaid major storm costs. The December 2008 major storm costs are currently recovered from customers at an annual rate of $6 million, beginning August 1, 2009, pursuant to the temporary distribution rate case settlement. This level of recovery could be modified once PSNH's permanent distribution rate case is decided in mid-2010. Offsetting this favorable cash flow impact was an increase in income tax payments largely attributable to the absence of bonus depreciation tax deductions under the American Recovery and Reinvestment Act of 2009 in the first quarter of 2010. Bonus depreciation tax deductions expired at the end of 2009.

RESULTS OF OPERATIONS – WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY

The components of significant income statement variances, higher/(lower) in comparison to the previous year, are provided in the table below.


Income Statement Variances	2010 versus 2009
(Millions of Dollars)	Amount		Percent
Operating Revenues	$	(18)	(15)	%

Operating Expenses:
Fuel, purchased and net interchange power		(20)	(31)
Other operating expenses		1	2
Maintenance		2	46
Depreciation		-	-
Amortization of regulatory (liabilities)/assets, net		(2)	(a)
Amortization of rate reduction bonds		-	-
Taxes other than income taxes		-	-
Total operating expenses		(19)	(18)

Operating Income		1	7

Interest expense		-	-
Other income/(loss), net		1	(a)
Income before income tax expense		2	22
Income tax expense		2	70
Net Income	$	-	-	%

(a) Percent greater than 100 not shown since not meaningful.

Comparison of the First Quarter of 2010 to the First Quarter of 2009

Operating Revenues

Operating revenues decreased $18 million in 2010 due to lower distribution segment revenues ($21 million), partially offset by higher transmission segment revenues ($3 million).

The distribution segment revenues decreased $21 million due primarily to a decrease in the portion of distribution revenues that does not impact earnings ($19 million). The portion of revenues that impacts earnings decreased $2 million. The 2010 retail sales as compared to the same period in 2009 decreased 4.4 percent.

The $19 million distribution segment revenues decrease that do not impact earnings was due primarily to a decrease in the portions of retail revenues that are included in DPU approved tracking mechanisms that track the recovery of certain incurred costs through WMECO's tariffs ($17 million) and transmission segment intracompany billings to the distribution segment that are eliminated in consolidation ($2 million). The distribution revenues included in DPU approved tracking mechanisms decreased $17 million due primarily to lower recovery of energy supply costs ($19 million), partially offset by higher transition cost recoveries ($2 million). The tracking mechanisms allow for rates to be changed periodically with overcollections refunded to customers or undercollections to be recovered from customers in future periods.

Fuel, Purchased and Net Interchange Power

Fuel, purchased and net interchange power expense decreased $20 million in 2010 due primarily to lower basic/default service supply costs. The basic/default service supply costs are the contractual amounts we must pay to various suppliers that serve this load after winning a competitive solicitation process. These costs decreased due primarily to lower supplier contract rates in addition to reduced load volumes.

Other Operating Expenses

Other operating expenses increased $1 million in 2010 as a result of higher distribution segment expenses mainly as a result of higher administrative and general expenses, including higher pension costs.

Maintenance

Maintenance expenses increased $2 million in 2010 due primarily to higher storm related expenses.

Amortization of Regulatory (Liabilities)/Assets, Net

Amortization of regulatory (liabilities)/assets, net, decreased $2 million in 2010 primarily as a result of the impact of the 2010 Healthcare Act related to income taxes.

Other Income/(Loss), Net

Other income/(loss), net, increased $1 million in 2010 due primarily to higher investment income due primarily to improved results from NU’s supplemental benefit trust and the absence of investment losses recorded in 2009.

Income Tax Expense

Income tax expense increased $2 million in 2010 due primarily to the impacts of the 2010 Healthcare Act.

LIQUIDITY

WMECO had cash flows provided by operating activities in the first quarter of 2010 of $4.8 million, compared with cash flows used in operating activities of $11.6 million in the first quarter of 2009 (amounts are net of RRB payments, which are included in financing activities). The improved cash flows in 2010 were due primarily to the absence in 2010 of costs related to the major storm in December 2008 that were paid to vendors in the first quarter of 2009. These costs were deferred and are expected to be recovered from customers. WMECO anticipates filing a distribution rate case in mid-2010, which would include a request for more timely recovery of the December 2008 storm costs. Offsetting this favorable cash flow impact was an increase in income tax payments largely attributable to the absence of bonus depreciation tax deductions under the American Recovery and Reinvestment Act of 2009 in the first quarter of 2010. Bonus depreciation tax deductions expired at the end of 2009.

ITEM 3.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Market Risk Information

Commodity Price Risk Management: Our Regulated companies enter into energy contracts to serve our customers and the economic impacts of those contracts are passed on to our customers. Accordingly, the Regulated companies have no exposure to loss of future earnings or fair values due to these market risk-sensitive instruments. The wholesale portfolio held by Select Energy includes contracts that are market-risk sensitive, including a wholesale energy sales contract through 2013 with an agency comprised of municipalities with approximately 0.4 million remaining MWh of supply contract volumes, net of related sales volumes. Select Energy also has a non-derivative energy contract that expires in mid-2012 to purchase output from a generation facility, which is less exposed to market price volatility. As Select Energy's contract volumes are winding down, and as the wholesale energy sales contract is substantially hedged against price risks, we have limited exposure to commodity price risks. We have no energy contracts entered into for trading purposes.

Sensitivity analysis provides a presentation of the potential loss of future pre-tax earnings and fair values from our market risk-sensitive contracts due to one or more hypothetical changes in commodity price components, or other similar price changes. We have provided this analysis in Part II, Item 7A, "Quantitative and Qualitative Disclosures about Market Risk," in our 2009 Form 10-K, which disclosures are incorporated herein by reference. There have been no additional market or commodity price risks identified and no material changes with regard to the sensitivity analysis previously disclosed in our 2009 Form 10-K.

Other Risk Management Activities

Interest Rate Risk Management: We manage our interest rate risk exposure in accordance with our written policies and procedures by maintaining a mix of fixed and variable rate long-term debt.

Credit Risk Management: Credit risk relates to the risk of loss that we would incur as a result of non-performance by counterparties pursuant to the terms of our contractual obligations. We serve a wide variety of customers and suppliers that include IPPs, industrial companies, gas and electric utilities, oil and gas producers, financial institutions, and other energy marketers. Margin accounts exist within this diverse group, and we realize interest receipts and payments related to balances outstanding in these margin accounts. This wide customer and supplier mix generates a need for a variety of contractual structures, products and terms that, in turn, require us to manage the portfolio of market risk inherent in those transactions in a manner consistent with the parameters established by our risk management process.

We have provided additional disclosures regarding interest rate risk management and credit risk management in Part II, Item 7A, "Quantitative and Qualitative Disclosures about Market Risk," in our 2009 Form 10-K, which are incorporated herein by reference. There have been no additional risks identified and no material changes with regard to the items previously disclosed in our 2009 Form 10-K.

For further information on cash collateral deposited and posted with counterparties as well as any cash collateral netted against the fair value of the related derivative contracts, see Note 1H, "Summary of Significant Accounting Policies - Special Deposits and Counterparty Deposits," and Note 2, “Derivative Instruments,” to the unaudited condensed consolidated financial statements. Additional quantitative and qualitative disclosures about market risk are set forth in Part I, Item 2, "Management's Discussion and Analysis of Financial Condition and Results of Operations," included in this Quarterly Report on Form 10-Q.

ITEM 4.

CONTROLS AND PROCEDURES

Management, on behalf of NU, CL&P, PSNH, and WMECO, evaluated the design and operation of the disclosure controls and procedures as of March 31, 2010 to determine whether they are effective in ensuring that the disclosure of required information is made timely and in accordance with the Securities Exchange Act of 1934 and the rules and regulations of the SEC. This evaluation was made under management's supervision and with management's participation, including the principal executive officers and principal financial officer as of the end of the period covered by this Quarterly Report on Form 10-Q. There are inherent limitations of disclosure controls and procedures, including the possibility of human error and the circumventing or overriding of the controls and procedures. Accordingly, even effective disclosure controls and procedures can only provide reasonable assurance of achieving their control objectives. The principal executive officers and principal financial officer have concluded, based on their review, that the disclosure controls and procedures of NU, CL&P, PSNH, and WMECO are effective to ensure that information required to be disclosed by us in reports filed under the Securities Exchange Act of 1934 (i) is recorded, processed, summarized, and reported within the time periods specified in SEC rules and regulations and (ii) is accumulated and communicated to management, including the principal executive officers and principal financial officer, as appropriate to allow timely decisions regarding required disclosures.

There have been no changes in internal controls over financial reporting for NU, CL&P, PSNH, and WMECO during the quarter ended March 31, 2010 that have materially affected, or are reasonably likely to materially affect, internal controls over financial reporting.

PART II. OTHER INFORMATION

ITEM 1.

LEGAL PROCEEDINGS

We are parties to various legal proceedings. We have identified these legal proceedings in Part I, Item 3, "Legal Proceedings," and elsewhere in our 2009 Form 10-K, which disclosures are incorporated herein by reference. There have been no additional legal proceedings identified and no material changes with regard to the legal proceedings previously disclosed in our 2009 Form 10-K.

ITEM 1A.

RISK FACTORS

We are subject to a variety of significant risks in addition to the matters set forth under "Forward Looking Statements," in Item 2, "Management's Discussion and Analysis of Financial Condition and Results of Operations," of this Quarterly Report on Form 10-Q. We have identified a number of these risk factors in Item 1A, "Risk Factors," in our 2009 Form 10-K, which risk factors are incorporated herein by reference. These risk factors should be considered carefully in evaluating our risk profile. There have been no additional risk factors identified and no material changes with regard to the risk factors previously disclosed in our 2009 Form 10-K.

ITEM 2.

UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

There were no purchases made by or on behalf of NU or any "affiliated purchaser" (as defined in Rule 10b-18(a)(3) under the Securities Exchange Act of 1934) of NU common shares during the quarter ended March 31, 2010.

ITEM 6.

EXHIBITS

Each document described below is incorporated by reference by the registrant(s) listed to the files identified, unless designated with a (*), which exhibits are filed herewith.

Exhibit No.

Description

Listing of Exhibits (NU)

*10

Tenth Supplemental Indenture of Mortgage dated as of April 1, 2010 between Yankee Gas Services Company and the Bank of New York Mellon Trust Company, as Trustee

*12

Ratio of Earnings to Fixed Charges

*15

Deloitte & Touche LLP Letter Regarding Unaudited Financial Information

*31

Certification of Charles W. Shivery, Chairman, President and Chief Executive Officer of Northeast Utilities, required by Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated May 7, 2010

*31.1

Certification of David R. McHale, Executive Vice President and Chief Financial Officer of Northeast Utilities, required by Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated May 7, 2010

*32

Certification of Charles W. Shivery, Chairman, President and Chief Executive Officer of Northeast Utilities and David R. McHale, Executive Vice President and Chief Financial Officer of Northeast Utilities, pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, dated May 7, 2010

Listing of Exhibits (CL&P)

*12

Ratio of Earnings to Fixed Charges

*31

Certification of Leon J. Olivier, Chief Executive Officer of The Connecticut Light and Power Company, required by Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated May 7, 2010

*31.1

Certification of David R. McHale, Executive Vice President and Chief Financial Officer of The Connecticut Light and Power Company, required by Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, May 7, 2010

*32

Certification of Leon J. Olivier, Chief Executive Officer of The Connecticut Light and Power Company and David R. McHale, Executive Vice President and Chief Financial Officer of The Connecticut Light and Power Company, pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, dated May 7, 2010

Listing of Exhibits (PSNH)

*12

Ratio of Earnings to Fixed Charges

*31

Certification of Leon J. Olivier, Chief Executive Officer of Public Service Company of New Hampshire, required by Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated May 7, 2010

*31.1

Certification of David R. McHale, Executive Vice President and Chief Financial Officer of Public Service Company of New Hampshire, required by Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated May 7, 2010

*32

Certification of Leon J. Olivier, Chief Executive Officer of Public Service Company of New Hampshire and David R. McHale, Executive Vice President and Chief Financial Officer of Public Service Company of New Hampshire, pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, dated May 7, 2010

Listing of Exhibits (WMECO)

Instruments defining the rights of security holders, including indentures

4.1

Fifth Supplemental Indenture between WMECO and The Bank of New York Mellon Trust Company , N.A., as Trustee, dated as of March 1, 2010 (Exhibit 4.1, WMECO Current Report on Form 8-K filed March 10, 2010, File No. 000-07624)

*12

Ratio of Earnings to Fixed Charges

*31

Certification of Leon J. Olivier, Chief Executive Officer of Western Massachusetts Electric Company, required by Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated May 7, 2010

*31.1

Certification of David R. McHale, Executive Vice President and Chief Financial Officer of Western Massachusetts Electric Company, required by Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated May 7, 2010

*32

Certification of Leon J. Olivier, Chief Executive Officer of Western Massachusetts Electric Company and David R. McHale, Executive Vice President and Chief Financial Officer of Western Massachusetts Electric Company, pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, dated May 7, 2010

SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.


		NORTHEAST UTILITIES
		(Registrant)




Date: May 7, 2010	By	/s/ David R. McHale
		David R. McHale
		Executive Vice President and Chief Financial Officer
		(for the Registrant and as Principal Financial Officer)

SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.


		THE CONNECTICUT LIGHT AND POWER COMPANY
		(Registrant)




Date: May 7, 2010	By	/s/ David R. McHale
		David R. McHale
		Executive Vice President and Chief Financial Officer
		(for the Registrant and as Principal Financial Officer)

SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.


		PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE
		(Registrant)




Date: May 7, 2010	By	/s/ David R. McHale
		David R. McHale
		Executive Vice President and Chief Financial Officer
		(for the Registrant and as Principal Financial Officer)

SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.


		WESTERN MASSACHUSETTS ELECTRIC COMPANY
		(Registrant)




Date: May 7, 2010	By	/s/ David R. McHale
		David R. McHale
		Executive Vice President and Chief Financial Officer
		(for the Registrant and as Principal Financial Officer)